SIXTH FLOOR, 900 HOWE STREET, BOX 250 VANCOUVER, B.C. V6Z 2N3 CANADA web site: http://www.bcuc.com IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 and An Application by Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek and Tumbler Ridge Divisions) for Approval to Amend 2004 Rates BEFORE: L.A. Boychuk, Panel Chair and Commissioner R.J. Milbourne, Commissioner N.F. Nicholls, Commissioner O R D E R WHEREAS: A. In a 2004 Revenue Requirements Application dated November 28, 2003 and revised on January 14, 2004 and February 23, 2004 (“Application”), Pacific Northern Gas (N.E.) Ltd. [“PNG(N.E.)”] applied for approval to increase the rates in the Fort St. John/Dawson Creek and Tumbler Ridge Divisions on an interim and final basis, effective January 1, 2004, pursuant to Sections 89 and 58 of the Utilities Commission Act; and B. The Application proposed to increase delivery rates to all customers as a result of increases in cost of service and decreased deliveries to most customer classes, except for the Tumbler Ridge Division where decreased cost of company use gas resulted in decreased delivery rates for sales service customers; and C. The Application also requested approval to continue to record in a deferral account the costs incurred to repair any damage caused by a terrorist act, and to fix the allocation of overhead to capital projects for 2004 at 19.4 percent in the Fort St. John/Dawson Creek Division and at 2.0 percent in the Tumbler Ridge Division; and D. The Application requested approval of a decrease to Gas Supply Charges for 2004 based on November 26, 2003 forward natural gas prices; and E. On December 8, 2003 PNG(N.E.) filed its Fourth Quarter 2003 Report on gas supply costs and Gas Cost Variance Account (“GCVA”) balances (“Report”), which reaffirmed the request in the Application regarding Gas Supply Charges for the Fort St. John/Dawson Creek Division and requested approval of a Gas Supply Charge of $5.177/GJ for the Tumbler Ridge Division, both for January 1, 2004; and F. The Report also requested the continuation or implementation of GCVA riders that would amortize the projected end-of-2003 GCVA balances over 2004 and 2005; and BR I T I S H CO L U M B I A U T I L I T I E S COM M I S S I ON OR D E R NU M B E R G -71-04 TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385 FACSIMILE: (604) 660-1102 ) ) ) July 29, 2004 ) …/2
BR I T I S H CO L U M B I A UT I L I T I E S COM M I S S I ON OR D E R NU M B E R G-71-04 2 G. Commission Order No. G-86-03 approved interim rate changes effective January 1, 2004 in the delivery rates and permanent rate changes in the Gas Supply Charge and GCVA rider for all classes of customers as filed in the Application and amended in the Report, except that the permanent Gas Supply Charge for the Tumbler Ridge Division was set at $5.593/GJ effective January 1, 2004. H. Commission Order No. G-86-03 also established a written hearing process to review the Application; and I. On January 30, 2004 PNG(N.E.) and its parent company, Pacific Northern Gas Ltd. (“PNG”), filed an application to recapitalize PNG under an income trust ownership structure (“Recapitalization Application”); and J. Commission Order No. G-22-04 established an oral hearing process to review the Recapitalization Application in conjunction with the oral proceeding established to review the revenue requirements application of PNG(N.E.)’s parent company, PNG; and K. The Commission has reviewed the 2004 Revenue Requirement Application and the evidence adduced thereon, all as set forth in the Reasons attached as Appendix A. NOW THEREFORE the Commission orders as follows: 1. The Commission has reduced the 2004 revenue deficiency by $52,000 for the Fort St. John/Dawson Creek Division and by $22,000 for the Tumbler Ridge Division, as filed in the schedules accompanying PNG(N.E.)’s February 23, 2004 revised Application and adjusted in the Reasons attached as Appendix A to this Order. 2. The approved rates for the Gas Delivery Charge for the Fort St. John/Dawson Creek Division are less than the interim rates which have been in effect since January 1, 2004. PNG(N.E.) is directed to file an amended Summary of Rates and Bill Comparison schedule conforming to the terms of the Reasons attached as Appendix A to this Order, along with a method for refunding excess payments back to customers. 3. The approved 2004 revenue deficiency and the resulting rates for the Gas Delivery Charge for the Tumbler Ridge Division are greater than the revenue deficiency used to derive the interim rates which have been in effect since January 1, 2004. The interim rates are now set as permanent from January 1 to July 31, 2004. PNG(N.E.) Tumbler Ridge Division is directed to recover the remainder of the approved forecast 2004 revenue deficiency over the five-month period from August 1 to December 31, 2004. The remainder referred to above is defined as being the approved forecast 2004 revenue deficiency less the amount already recovered during the period from January 1 to July 31, 2004. PNG(N.E.) Tumbler Ridge Division is to file an amended Summary of Rates and Bill Comparison schedule conforming to the terms of the Reasons attached as Appendix A to this Order. .../3
4. The request to continue record in a deferral account the costs incurred to repair any damage caused by a terrorist act, and to fix the allocation of overhead to capital projects for 2004 at 19.4 percent in the Fort St. John/Dawson Creek Division and at 2.0 percent in the Tumbler Ridge Division is approved. 5. The Commission will accept, subject to timely filing, amended Gas Tariff Rate Schedules in accordance with this Order. 6. PNG(N.E.) is to inform all affected customers of the final rates by way of a customer notice. DATED at the City of Vancouver, in the Province of British Columbia, this Attachments BR I T I S H CO L U M B I A UT I L I T I E S COM M I S S I ON OR D E R NU M B E R G-71-04 3 29 th day of July 2004. BY ORDER Original signed by: Lori Ann Boychuk Panel Chair and Commissioner .../3
APPENDIX A to Order No. G-71-04 Page 1 of 14 PACIFIC NORTHERN GAS (N.E.) LTD. 2004 REVENUE REQUIREMENTS APPLICATION REASONS FOR DECISION 1.0 INTRODUCTION 1.1 Background Pacific Northern Gas (N.E.) Ltd. [“PNG(N.E.)”, “Company”, “Utility”] is a wholly owned subsidiary of Pacific Northern Gas Ltd. (“PNG”) and serves customers in the Fort St. John, Taylor, Dawson Creek, Pouce Coupe, and Tumbler Ridge areas of northeastern British Columbia. The Fort St. John/Dawson Creek (“FSJ/DC”) Division receives natural gas from the Duke Energy Gas Transmission (“Duke”) transmission pipeline system and the Williams Energy (Canada) Inc. West Stoddart pipeline. The Tumbler Ridge (“TR”) Division obtains all its raw gas supply from Canadian Natural Resources Limited (“CNRL”) and operates its own small gas processing plant. The parent company, PNG, delivers natural gas to customers, including large industrial operations, in a region west of Prince George to tidewater at Kitimat and Prince Rupert. PNG’s head office is in Vancouver. Customer service and administrative functions for both PNG and PNG(N.E.) are supported from a regional office in Terrace. Although PNG(N.E.) has construction, operation, and maintenance staff located in its service territory, PNG provides PNG(N.E.) with most of its administrative, support, and gas supply services. 1.2 The Application In a 2004 Revenue Requirements Application dated November 28, 2003 and revised on January 14, 2004 and February 23, 2004 (“Application”), PNG(N.E.) applied for approval to increase the rates in the Fort St. John/Dawson Creek and Tumbler Ridge Divisions on an interim and final basis, effective January 1, 2004, pursuant to Sections 89 and 58 of the Utilities Commission Act (“Act”). The Application proposed to increase delivery rates to all customers as a result of increases in cost of service and decreased deliveries to most customer classes, except for the Tumbler Ridge Division where decreased cost of company use gas resulted in decreased delivery rates for sales service customers. PNG(N.E.) also requested approval of a decrease to Fort St. John/Dawson Creek Gas Supply Charges for 2004 and filed its Fourth Quarter 2003 Report on gas supply costs and Gas Cost Variance Account (“GCVA”) balances (“the Report”), in support. The Report requested approval of changes to the Tumbler Ridge Division Gas Supply Charge and requested the continuation or implementation of GCVA riders that would amortize the projected end-of-2003 GCVA balances over 2004 and 2005.
APPENDIX A to Order No. G-71-04 Page 2 of 14 Commission Order No. G-86-03 approved interim delivery rate changes effective January 1, 2004 and permanent rate changes in the Gas Supply Charge and GCVA rider for all classes of customers as filed in the Application and amended in the Report, except that the permanent Gas Supply Charge for the Tumbler Ridge Division was set at $5.593/GJ effective January 1, 2004. 1.3 The Written Hearing Process Commission Order No. G-86-03 established a written hearing process to review the Application on December 18, 2003. Interventions were received from by the British Columbia Public Interest Advocacy Centre on behalf of the BC Old Age Pensioners’ Organization, Council of Senior Citizens’ Organizations, federated anti-poverty groups of BC, Senior Citizen’s Association of BC, End Legislated Poverty, West End Seniors’ Network, and the Tenants Rights Action Coalition (collectively “BCOAPO et al.”). The B.C. Ministry of Energy and Mines and the Peace River Regional District (“PRRD”) also intervened. After a series of information requests and responses, submissions were received from BCOAPO et al. and the PRRD. The PRRD was concerned with the magnitude of the rate increases requested by PNG(N.E.) and asked the Commission to carefully scrutinize each increase in the various costs. BCOAPO et al. noted that PNG has proposed in its Recapitalization Application that its future rates be established using all of the same ratemaking principles and mechanisms which are currently in place and submitted that the Recapitalization Application by PNG makes it inappropriate that PNG(N.E.) attempt to make changes to the status quo at this time. PNG(N.E.) filed its Final Argument on March 5, 2004. The Company notes that neither intervenor has provided any information in their submissions that refute what PNG(N.E.) states that it needs to maintain reliable, secure and safe service. It also submits that the changes being requested would be needed regardless of the outcome of the Recapitalization Application. 2.0 LOAD FORECAST 2.1 Fort St. John Residential PNG(N.E.) forecasts deliveries of 1,093,258 GJ to its residential customers in Fort St. John. The forecast is broadly based on a 2004 forecast weighted average customer count of 8,170 and a 2004 forecast use per account of 133.8 GJ per customer (Ex. B-6, Tab Application, FSJ/DC, pp. 18-19). The weighted average forecast customer count equals the year-end 2003 customer count plus forecast net customer additions multiplied by a 30 percent equivalence factor to account for the changes in the customer additions that occur over the course of the test year, such as additions from new construction or subtractions from service removals. The 2003
APPENDIX A to Order No. G-71-04 Page 3 of 14 year-end customer count equals 8,118. PNG(N.E.) forecasts 174 net customer additions in the 2004 test year, equal to 52 additions when multiplied by the equivalence factor, for a total weighted average customer count in the 2004 test year of 8,170 (Ex. B-5, Tab 1, pp. 20-23; Ex. B-6, Tab Application, FSJ/DC, pp. 18-19). The Commission accepts the weighted average customer count forecast of 8,170. PNG(N.E.) forecasts test year 2004 residential use per account as the mid-point between actual normalized 2003 use per account and a linear trend estimate of 2004 use account. PNG(N.E.) considers this to be a reasonable approach given the challenge to forecast deliveries having regard to customer behaviour, economic conditions and the gas supply market (Ex. B-1, Tab Application FSJ/DC, p. 18). The Commission accepts PNG(N.E.)’s use of the mid-point between actual 2003 use per account and the 2004 linear trend estimate as a reasonable methodology to forecast residential use per account at this time. The Commission notes that the marked change in residential use per account over the last 3 years compared to historical trends and the establishment of an RSAM account for PNG(N.E.) are consistent with PNG(N.E.)’s submissions on the reasonableness of its approach. In its initial application, PNG estimated a 2004 linear trend of 145.8 GJ per customer based on data from 1992 through 2002 (Ex. B-1, Tab Application FSJ/DC, p. 18; Ex. B-5, Tab 1, pp. 14-15). The Commission replicated substantially the same linear trend of use per account using the formula and data set that PNG provided in response to Commission IR No. 1, Q. 8.3 (see Ex. B-5, Tab 1, pp. 14-15). In PNG’s revised application, actual 2003 use per account equals 133.3 GJ per customer, and the 2004 linear trend is updated to equal 134.3 (Ex. B-6, Tab Application, FSJ/DC, p. 18). The Commission was not able to substantially replicate the same result as PNG with the addition of actual 2003 data to the linear trend estimation, but rather the Commission estimates a 2004 linear trend use per account of 140.7 GJ per customer. The Commission notes that a data set for Fort St. John residential use per account that PNG provided during its 2003 revenue requirements hearing is the same in all material respects as the data set provided in this proceeding except for a marked difference in year 2000 data. When this earlier data set is used along with 2003 actual data, the Commission replicates substantially the same linear trend estimate that PNG provides in its revised application. The Commission is unable to discern why specific data has varied between application years or between application iterations, whether associated with customer reclassifications or reporting and estimation errors, for example. For this reason, and because the RSAM account will mitigate the impact of any potential errors, the Commission accepts PNG’s use per account forecast of 133.8, and thereby the Commission accepts the 2004 deliveries forecast of 1,093,258 GJ for PNG(N.E.)’s residential customers in Fort St. John. The Commission directs PNG in future applications to explicitly identify the cause of any data variations between application years or between application iterations.
APPENDIX A to Order No. G-71-04 Page 4 of 14 Small Commercial PNG(N.E.) forecasts deliveries of 801,557 GJ to its small commercial customers in Fort St. John. The forecast is broadly based on a 2004 forecast weighted average customer count of 1,351 and a 2004 forecast use per account of 592.9 GJ per customer (Ex. B-6, Tab Application, FSJ/DC, pp. 18-19). PNG(N.E.) uses the same customer count methodology as it does for its residential customer class, although net small commercial customer additions are adjusted by a 35 percent equivalence factor given a difference in the components of net customer additions as compared to the residential class (see Ex. B-5, Tab 1, pp. 20-23). The 2004 weighted average customer count forecast equals the 2003 year-end customer count of 1,337 plus a net equivalence-adjusted addition of 14 customers (Ex. B-6, Tab Application, FSJ/DC, p. 19). This is an increase in net customer additions compared to PNG(N.E.)’s initial application (See Ex. B-1, Tab Application, FSJ/DC, p. 19 and Ex. B-5, Tab 1, pp. 20-23). PNG uses the same mid-point use per account forecast methodology as it does for its residential customer class, although it increased the mid-point forecast of small commercial use per account to adjust for the reclassification of some large commercial customers to the small commercial class. The Commission replicates substantially the same small commercial linear trend estimate as PNG(N.E.). The Commission finds that PNG(N.E.) has appropriately increased the mid-point estimate of small commercial use per account to adjust for the reclassification of customers to the large commercial class. The Commission accepts PNG(N.E.)’s weighted average customer count forecast of 1,351 and its use per account forecast of 592.9 GJ per customer, and thereby accepts the 2004 deliveries forecast of 801,557 GJ for Fort St. John small commercial customers. Large Commercial PNG(N.E.) forecasts deliveries of 138,150 GJ to its large commercial customers. The forecast is based on a review of historical deliveries and expected use in 2004 based on discussions with these customers. PNG considers that this is an appropriate methodology given how few customers are in this class (Ex. B-6, Tab Application, FSJ/DC, pp. 21-22). Seven large commercial customers were reclassified as small commercial customers while three small commercial customers were moved to the large commercial class (Ex. B-6, FSJ/DC, p. 3; Ex. B-6, Tab Application, FSJ/DC, p.18). In 2003 PNG(N.E.) forecast deliveries of 167,000 GJ to its large commercial customers, while the Commission set 2003 test year deliveries at 179,000 GJ (Commission Order No. G-22-03, Appendix A, p. 5). Actual deliveries in 2003 were lower, totaling 150,151 GJ (Ex. B-6, Tab Application, FSJ/DC, p. 21). Given the forecast methodology, the reclassification of customers and the historical context, the Commission considers that the 2004 forecast is reasonable. The Commission accepts the 2004 deliveries forecast of 138,150 GJ for PNG(N.E.)’s large commercial customers in Fort St. John.
APPENDIX A to Order No. G-71-04 Page 5 of 14 Small Industrial PNG(N.E.) forecasts deliveries of 119,020 GJ to its small industrial customers and 1,315,300 GJ to its transportation service customers. Likewise as for its large commercial customers, PNG bases its small industrial load forecast on a review of historical deliveries and expected use in 2004 based on discussions with these customers (Ex. B-6, Tab Application, FSJ/DC, pp. 21-22). In the 2003 PNG(N.E.) Revenue Requirements Decision, the Commission approved 2003 small industrial and transportation deliveries of 151,500 GJ and 1,200,800 GJ, respectively, while actual 2003 deliveries for these customers were lower at 96,754 GJ and 1,179,256 GJ (Ex. B-6, Tab Application, FSJ/DC, p. 22). Given the forecast methodology and the historical context, the Commission considers that the 2004 forecast is reasonable. The Commission accepts the 2004 deliveries forecast for PNG(N.E.)’s small industrial customers in Fort St. John. 2.2 Dawson Creek Residential PNG(N.E.) forecasts deliveries of 628,312 GJ to its residential customers in Dawson Creek. The forecast is broadly based on a 2004 forecast weighted average customer count of 5,064 and a 2004 forecast use per account of 124.1 GJ per customer (Ex. B-6, Tab Application, FSJ/DC, pp. 20-21). PNG(N.E.) uses the same load forecast methodologies as the Commission accepts for PNG(N.E.)’s Fort St. John residential customers. Likewise, the Commission accepts the same methodologies for PNG(N.E)’s Dawson Creek load forecast. The 2004 weighted average customer count forecast equals the 2003 year-end customer count of 5,054 plus a net equivalence-adjusted addition of 10 customers (Ex. B-6, Tab Application, FSJ/DC, p. 20; Ex. B-5, Tab 1, pp. 20-23). PNG(N.E.)’s use per account forecast for Dawson Creek residential customers varies in the same manner as its forecast for its Fort St. John residential customers (see the Commission’s discussion of the nature of the variations in the Fort St. John residential load forecast section). The Commission is able to replicate substantially the same Dawson Creek residential load forecast estimate as PNG(N.E.) when using PNG(N.E.)’s 2003 revenue requirements data set along with 2003 actual data from its revised 2004 application. The Commission accepts PNG(N.E.)’s weighted average customer count forecast of 5,064 and its use per account forecast of 124.1 GJ per customer, and thereby accepts the 2004 deliveries forecast of 628,312 GJ for Dawson Creek residential customers. Likewise as for its Fort St John Load forecast, the Commission directs PNG in future applications to explicitly identify the cause of any data variations between application years or between application iterations, as such variations may be associated with customer reclassifications or reporting and estimation errors, for example.
APPENDIX A to Order No. G-71-04 Page 6 of 14 Small Commercial PNG(N.E.) forecasts deliveries of 483,510 GJ to its small commercial customers in Dawson Creek. The forecast is broadly based on a 2004 forecast weighted average customer count of 700 and a 2004 forecast use per account of 690.7 GJ per customer (Ex. B-6, Tab Application, FSJ/DC, pp. 20-21). PNG(N.E.) uses the same load forecast methodologies as the Commission accepts for PNG(N.E.)’s Fort St. John small commercial customers. Likewise, the Commission accepts the same methodologies for PNG(N.E)’s Dawson Creek load forecast. The 2004 weighted average customer count forecast equals the 2003 year-end customer count of 698 plus a net equivalence-adjusted addition of 2 customers (Ex. B-6, Tab Application, FSJ/DC, p. 20; Ex. B-5, Tab 1, pp. 20-23). PNG increased its mid-point forecast of small commercial use per account to adjust for the reclassification of some large commercial customers in Dawson Creek to the small commercial class. The Commission finds that PNG(N.E.)’s adjusted increase to the mid-point estimate of small commercial use per account is reasonable. The Commission accepts PNG(N.E.)’s weighted average customer count forecast of 700 and its use per account forecast of 690.7 GJ per customer, and thereby accepts the 2004 deliveries forecast of 483,510 GJ for Dawson Creek small commercial customers. Large Commercial PNG(N.E.) forecasts deliveries of 160,900 GJ to its large commercial customers. The forecast is based on a review of historical deliveries and expected use in 2004 based on discussions with these customers. PNG considers that this is an appropriate methodology given how few customers are in this class (Ex. B-6, Tab Application, FSJ/DC, pp. 21-22). The Commission notes that some large commercial customers have been reclassified to the small commercial customer class. In the 2003 PNG(N.E.) revenue requirements application, PNG(N.E.) forecast deliveries of 137,400 GJ to its large commercial customers in Dawson Creek (Commission Order No. G-22-03, Appendix A, p. 7). In its Decision, the Commission approved 2003 large commercial deliveries of 148,000 GJ, while actual 2003 deliveries for these customers were higher at 155,822 GJ (Commission Order No. G-22-03, Appendix A, p. 7; Ex. B-6, Tab Application, FSJ/DC, p. 22). The 2004 test year forecast for Dawson Creek is higher than both the approved and actual deliveries in 2003. The Commission considers that the 2004 forecast is reasonable. The Commission accepts the 2004 deliveries forecast of 160,900 GJ for PNG(N.E.)’s large commercial customers in Dawson Creek.
APPENDIX A to Order No. G-71-04 Page 7 of 14 Small Industrial PNG(N.E.) forecasts deliveries of 130,000 GJ to its small industrial customer in Dawson Creek, the Louisiana Pacific veneer and panel board mill, based on discussions with this customer (Ex. B-6, Tab Application FSJ/DC, p. 22). This forecast is subject to an Industrial Customer Deliveries Deferral Account (“ICDDA”) to record any variance between forecast and actual margin. The account was initially established to mitigate a high degree of variation and uncertainty in the load forecast of this customer. The 2004 forecast (130,000 GJ) is markedly higher than the Commission’s approved 2003 forecast of 50,000 GJ and actual 2003 deliveries of 81,565. The 2004 forecast reflects Louisiana Pacific’s best estimate of consumption with the completion of renovations at the mill, a level it regards as consistent with its consumption prior to carrying out renovations. Consumption in 2000 was just over 200,000 GJ. PNG states that it would recommend a forecast of 75,000 GJ to this customer if there was no deferral account in place (Ex. B-5, Tab 1, pp. 28-29). The Commission accepts the 2004 small industrial forecast and directs PNG(N.E.) to continue to apply the ICDDA to variances between the forecast and actual margin of its small industrial customer in Dawson Creek in 2004. Given that renovations are complete at the Louisiana Pacific mill and that the forecast is based on discussions with the customer, the Commission expects to examine the need for continued use of the deferral account at PNG(N.E.)’s next revenue requirements hearing. 2.3 Tumbler Ridge Residential PNG(N.E.) forecasts deliveries of 86,862 GJ to its residential customers in Tumbler Ridge. The forecast is broadly based on a 2004 forecast weighted average customer count of 1,046 and a 2004 forecast use per account of 83.0 GJ per customer (Ex. B-6, Tab Application, Tumbler Ridge, pp. 14-15). PNG(N.E.) uses the same load forecast methodologies as the Commission accepts for PNG(N.E.)’s Fort St. John and Dawson Creek residential customers. Likewise, the Commission accepts the same methodologies for PNG(N.E)’s Tumbler Ridge load forecast. The 2004 weighted average customer count forecast equals the 2003 year-end customer count of 1,052 plus a net equivalence-adjusted subtraction of 6 customers (Ex. B-6, Tab Application, Tumbler Ridge, p. 15; Ex. B-5, Tab 1, pp. 20-23). A reduced forecast compared to the actual 2003 residential customer count is consistent with the recent historical trend for Tumbler Ridge. The Commission accepts PNG(N.E.)’s weighted average customer count forecast of 1,046 and its use per account forecast of 83.0 GJ per customer, and thereby accepts the 2004 deliveries forecast of 86,862 GJ for Tumbler Ridge residential customers.
APPENDIX A to Order No. G-71-04 Page 8 of 14 Small Commercial PNG(N.E.) forecasts deliveries of 27,435 GJ to its small commercial customers in Tumbler Ridge. The forecast is broadly based on a 2004 forecast weighted average customer count of 62 and a 2004 forecast use per account of 445.3 GJ per customer (Ex. B-6, Tab Application, Tumbler Ridge, pp. 14-15). PNG(N.E.) uses the same load forecast methodologies as the Commission accepts for PNG(N.E.)’s Fort St. John and Dawson Creek small commercial customers. Likewise, the Commission accepts the same methodologies for PNG(N.E)’s Tumbler Ridge load forecast. The 2004 weighted average customer count forecast equals the 2003 year-end customer count of 65 plus a net equivalence-adjusted subtraction of 3 customers (Ex. B-6, Tab Application, Tumbler Ridge, p. 15; Ex. B-5, Tab 1, pp. 20-23). The Commission accepts PNG(N.E.)’s weighted average customer count forecast of 62 and its use per account forecast of 445.3 GJ per customer, and thereby accepts the 2004 deliveries forecast of 27,435 GJ for Tumbler Ridge small commercial customers. Large Commercial PNG(N.E.) forecasts deliveries of 20,000 GJ to its large commercial customers. The forecast is based on a review of historical deliveries and expected use in 2004 based on discussions with these customers. PNG considers that this is an appropriate methodology given how few customers are in this class (Ex. B-6, Tab Application, Tumbler Ridge, p. 16). The 2004 forecast is comparable to actual 2003 deliveries of 19,176 GJ. The Commission accepts the large commercial deliveries forecast for Tumbler Ridge. Small Industrial Transportation Service PNG(N.E.) forecasts deliveries of 580,000 GJ to its small industrial transportation service customer in Tumbler Ridge. The forecast is comparable to both the deliveries approved by the Commission in 2003 (586,000 GJ) and actual 2003 deliveries (588,083 GJ). The Commission accepts the small industrial transportation service deliveries forecast for Tumbler Ridge.
APPENDIX A to Order No. G-71-04 Page 9 of 14 3.0 RETURN ON EQUITY (“ROE”) AND CAPITAL STRUCTURE PNG(N.E.)’s rate of return on equity is based on a Commission approved rate of return for a low-risk benchmark utility plus an approved risk premium determined in the particular circumstances of PNG(N.E.). The Commission updates the rate of return for a low-risk benchmark utility through an annual ROE adjustment mechanism based on forecast long-term Canada bond yields. PNG(N.E.) has applied for a return on equity of 9.65 percent and a deemed common equity ratio of 36 percent for its Fort St. John/Dawson Creek division. The requested deemed common equity component is unchanged from 2003. The 9.65 percent rate of return is based on a low-risk benchmark return of 9.15 percent for 2004 plus an applied for risk premium of 50 basis points. PNG(N.E.) has applied for a return on equity of 9.90 percent and a deemed common equity ratio of 36 percent for its Tumbler Ridge division. The requested deemed common equity component is unchanged from 2003. The 9.90 percent rate of return is based on a low-risk benchmark return of 9.15 percent for 2004 plus an applied for risk premium of 75 basis points. In 2003 the Commission established a Revenue Stabilization Adjustment Mechanism (“RSAM”) deferral account for PNG(N.E.) to record the variance between the forecast and actual delivery margin of the Utility’s residential and small commercial customers in both its Fort St. John/Dawson Creek and Tumbler Ridge divisions. Given the consequent reduction in PNG(N.E.)’s risk, the Commission determined that the establishment of the RSAM account be accompanied by a reduction of 10 basis points in the equity risk premium, from 50 to 40 basis points in the Fort St. John/Dawson Creek division and from 75 to 65 basis points in the Tumbler Ridge division. The 10 basis points reduction was equal to the reduction that the Commission determined for Terasen Gas when its RSAM was introduced (Commission Order No. G-22-03, Appendix A, p. 16). PNG(N.E.) argues that the reduction in the risk premium of Terasen Gas, a low-risk benchmark utility, increased the relative risk premium of other utilities. So therefore, PNG(N.E.) argues, when Terasen Gas’ risk premium was increased by 10 basis points shortly after its RSAM was established, other utilities lost 10 basis points on a relative basis. PNG(N.E.) argues that its risk premium should not have been reduced when its RSAM was established as it had effectively occurred already at the time that Terasen’s risk premium was increased by 10 basis points while PNG(N.E.)’s risk premium was not (Ex. B-7, p. 6). BCOAPO et al. submits that whatever happened back in the 1990’s with Terasen’s risk premium is not relevant to the impact of the RSAM for PNG(N.E.) in 2004. BCOAPO et al. al submits that there is no evidence that PNG(N.E.)’s risk profile is any different under an RSAM in 2004 than under an RSAM in 2003. Therefore, BCOAPO et al. argues that there is no justification for increasing the risk premium by 10 basis points (Ex. C2-3, p. 4).
APPENDIX A to Order No. G-71-04 Page 10 of 14 The Commission notes that when it reduced the risk premium of Terasen Gas in the first instance, and increased its risk premium in the second instance as a result of an NSP, it was not making a determination on the actual or relative risk premium of other utilities such as PNG(N.E.) on a go forward basis, rather, it was strictly addressing the specific issues and trade-offs in the circumstances of Terasen Gas and its intervenors. The Commission agrees with BCOAPO et al. that the circumstances in respect of the risk premium for Terasen Gas should not factor into its determination of the risk premium for PNG(N.E.)’s Fort St. John/Dawson Creek and Tumbler Ridge divisions in 2004. The Commission is strictly concerned about determining the appropriate risk premium having regard to this Utility’s level of risk in 2004. The Commission reduced PNG(N.E.)’s risk premium by 10 basis points in 2003 to accompany the establishment of the RSAM account and the consequent reduction to PNG(N.E.)’s risk at that time. The reduction in the risk premium of Terasen Gas when its RSAM account was established served as a reference point to the Commission for the amount of the initial reduction in PNG(N.E.)’s risk premium when its RSAM account was introduced in 2003. The subsequent circumstances and Commission decisions in respect of Terasen Gas have no bearing on the Commission’s 2004 decision in respect of PNG(N.E.). The Commission determines that there is no material increase in the risk that PNG(N.E.) faces in 2004 relative to its circumstances in 2003 and the Commission’s determination in regard to PNG’s risk premium at that time. PNG(N.E.)’s Fort St. John/Dawson Creek division is characterized by stable revenues, a high proportion of delivery margin recovered from residential and small commercial customers, and little competitive rate pressure from alternatives such as electricity. PNG(N.E.)’s Tumbler Ridge division is a comparatively small utility but it is also characterized by relatively stable revenues with an RSAM account. The Commission believes that increases to the risk premiums of the Fort St. John/Dawson Creek and Tumbler Ridge divisions are unwarranted. The Commission denies PNG(N.E.)’s application to increase the risk premium in its Fort St. John/Dawson Creek and Tumbler Ridge divisions by 10 basis points.
APPENDIX A to Order No. G-71-04 Page 11 of 14 4.0 CAPITAL EXPENDITURES 4.1 Fort St. John/Dawson Creek Capital Additions planned for 2004 have been set at $2,215,000. This is an increase of 9.27 percent or $188,000 over 2003 (Application, page 17). The major components that account for 70 percent of capital additions are as follows (Ex. B-5, BCUC IR#1, page 3, Feb.13, 2004). Major Components of Capital Additions New Services Installation $ 222,000 New Mains Installation $ 104,000 New Meter Sets $ 33,000 Relocating Meter from Inside to Outside $ 123,000 Replacement of Beta 2306 PE pipe $ 188,000 Removal Of Underground Dresser fittings $ 205,000 Replacement of transportation equipment $ 112,000 Replacement of heavy equipment $ 122,000 Regulator Station Modifications $ 77,000 Total $ 1,186,000 New Services, Mains and Meter Sets The installation of mains, services and meter sets reflect the growth in customer additions. Relocation of Meters The replacement of polyethylene pipe, removal of underground fittings and meter relocation are all projects related to the safety and reliability of the system. Replacement of Transportation Equipment Three vehicles are to be replaced at a cost of $112,000. Two vehicles conform to the Company’s replacement guidelines of 7 years or 160,000 km. while a third vehicle has exhibited excessive maintenance costs. BCOAPO et al. indicated that since PNG(N.E.) has already paid for repairs that total $5,500, the vehicle should be used for one more year. Replacement of Heavy Equipment This is the cost for the replacement of a 1986 backhoe. Regulator Station Modifications There regulator station modifications are necessary are necessary for safe reliable operation.
APPENDIX A to Order No. G-71-04 Page 12 of 14 The Commission accepts the proposed capital additions of $2,215,000. 4.2 Tumbler Ridge Table No. 1 - Capital Additions Air Dryer System $ 15,000 Waste Storage Tank $ 30,000 Annual Plant Turnaround $ 50,000 Total $ 95,000 The Commission accepts the capital addition forecast. 5.0 EXPENSES 5.1 Company Use Gas Cost Rate The total Company Use Gas Cost Rate of $.0370/GJ is based on the November 26, 2003 forward gas price strip. The Commission accepts the Company Use Gas Cost Rate of $.0370/GJ. 5.2 Modification to GCVA Deferral Accounting Applicable to Company Use Gas PNG proposes to record the difference between actual cost of Company Use Gas and the amount recovered in rates by applying the Company Use Gas cost recovery rate to actual deliveries. PNG considers this proposed methodology to be more consistent with the method that GCVA balances are determined with respect to gas sales to the core market. The actual cost of company use gas is compared to the amount recovered in rates based on actual deliveries (Ex. B-1, Application, page 24). Proposed Commodity Cost Deferral Account = Total Actual Cost of Company Use Gas – (Actual Gas Deliveries x Forecasted Company Use Gas Unit Rate) Although PNG(N.E.) expects the modification to have a minor impact, the Company is instructed not to modify the GCVA Deferral accounting applicable to Company Use Gas. It is the Commission’s view that PNG should be somewhat at risk for the accuracy of Company Use Gas and forecasts. The proposed method limits that exposure as it is based on actual amounts rather than forecast. The Commission does not consider that a need to change the methodology has been demonstrated and denies the request.
APPENDIX A to Order No. G-71-04 Page 13 of 14 5.3 Interest Expense The terms and conditions of debt in the PNG(N.E.) divisions reflect the terms and conditions of the underlying third-party debt instruments in its parent, PNG. In 2004, PNG(N.E.) proposes to borrow from PNG a majority of the funds obtained by PNG under its 2012 RoyNat Debenture and to reallocate the 2018 Debenture financing among the PNG(N.E.) divisions. While the interest expense is higher, the changes result in a better matching of funding long-term assets with long-term liabilities. The 2012 Debenture carries a floating rate which PNG proposes to fix at rates available in the market if the income trust application is not approved. BCOAPO et al. argues that the Commission should not approve the fixing of the debenture as PNG has not provided an economic forecast to indicate interest rates increasing in the near future. However, PNG(N.E.) notes that the rates will remain floating pending the Commission’s decision, and any differences between the interest expense estimates in this Application and actual rates will continue to be captured in a deferral account. The Commission agrees with PNG(N.E.)’s proposed treatment. 5.4 Employee Benefits PNG(N.E.) seeks an increase in employee benefit costs for 2004 of $130,000 for FSJ/DC and $19,000 for TR, mainly due to pension fund asset experience losses and the restructuring of other post-retirement benefit programs. The 2004 pension forecast is based on the latest annual asset valuation which was completed in September 2003 and BCOAPO et al. submits that the correct amount of pension expense will not be determined unit the 2004 actuarial valuation is conducted. However, PNG(N.E.) argues that the 2004 pension expense is the amount, by law, that it is currently required to fund. The Commission approves the pension expense treatment proposed by PNG(N.E.). Other post-retirement benefit programs are to be treated in a manner consistent with the Commission’s Decision on PNG’s 2004 Revenue Requirements Application. 5.5 Shared Service Charges by PNG to PNG(N.E.) PNG(N.E.) receives an allocation from PNG for the cost of various shared services such as customer care, engineering and administration. The allocations are based on historical time studies, employee and customer counts. The shared service charges estimated to be billed to FSJ/DC in 2004 have increased by $225,000 or 23 percent over 2003 levels. In its last Settlement, PNG agreed to review the operating and maintenance accounts to be included in the cost pool for allocation and to update the historical time study used as the base for some of the allocations. PNG did conduct an internal time study for the period of April 1, 2003 to October 3, 2003, with all Vancouver-based employees participating. The PRRD expressed concern about the amount of information provided by PNG(N.E.) to justify the increased costs, noting that the study did not detail how hours were logged and accounted for. However, PNG(N.E.) replied that the process utilized was
APPENDIX A to Order No. G-71-04 Page 14 of 14 reasonable and that there is no better means to determine the appropriate indicator of time spent. As a result of the study, the percentage costs allocated to the Fort St John/ Dawson Creek division has increased from 14.1 percent to 19.4 percent. In addition to the increase in allocation rate, the Company has also increased the benefit surcharge from 25 percent to 31 percent to reflect the significant increase in pension and other benefits. The Commission agrees with the methodology used to allocate the PNG shared service costs to PNG(N.E.) The reasonableness of the parent company costs will be determined in the PNG revenue requirements proceeding and any disallowances should be followed through in the allocations. 5.6 Customer Care Costs PNG(N.E.) Account 713 Customer Billing costs (excluding shared services) have increased over 2003 Decision levels by about 23 percent in FSJ/DC division and have doubled in TR. The Company states that the increase results from more accurately estimating its share of the outside billing services costs paid by PNG. However, BCOAPO et al. submits that the Company did not carry out the 2003 Commission Order to present evidence that justifies the higher customer billing costs. PNG(N.E.) explained that it has a long term contract with the service provider that expires in 2008 and the terms and conditions of the contract were reviewed by the Commission at the time the service provider was engaged. However, the Company also states that the cost increases relate to special requests for system upgrades, rate code restructuring and bill viewing changes, none of which were vetted by the Commission. In the absence of full justification, Commission Order No. G-22-03 considered that the 2003 increase in the cost per customer for Customer Billing was excessive and allowed an increase for inflation only. In the continued absence of sufficient justification, the Commission will again allow per customer increases for inflation only. Therefore, Account 713 Customer Billing expense in FSJ/DC is reduced from $319,000 to $267,000 ($17.00/customer +2.5% x 15,318 average number of customers for 2004) or $52,000. Account 713 Customer Billing expense in TR is reduced from $43,000 to $21,000 ($18.50/customer +2.5% x 1,110 average number of customers for 2004) or $22,000.
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