BRITISH COL UMBIA UTILITIES COM MISSION
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 Application by Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek and Tumbler Ridge Divisions) for Approval of 2006 Rates
BEFORE: L.A. Boychuk, Panel Chair and Commissioner August 16, 2006 O R D E R WHEREAS: A. On November 30, 2005, Pacific Northern Gas (N.E.) Ltd. Fort St. John/Dawson Creek and Tumbler Ridge Divisions [“PNG (N.E.)”] filed for approval of its 2006 Revenue Requirements Application (“the Application”). PNG (N.E.) proposed to amend its rates on an interim and final basis, effective January 1, 2006, pursuant to Sections 89 and 58 of the Utilities Commission Act (“the Act”); and
B. The Application proposes to increase delivery rates to all customers primarily as a result of increases in the cost of service, including the cost of company use gas; and
C. On December 12, 2005 PNG (N.E.) filed its Fourth Quarter 2005 Report on gas supply costs and Gas Cost Variance Account (“GCVA”) balances (“the Report”), and requested changes to Gas Supply Cost Recovery Rates for the Fort St. John/Dawson Creek and Tumbler Ridge Divisions effective January 1, 2006 based on November 28, 2005 natural gas forward prices. PNG (N.E.) proposed that no changes be made to GCVA rate riders; and
D. The Report projected a debit balance of $1,516,000 in the Fort St. John/Dawson Creek GCVA at December 31, 2005, which would require an increase in the GCVA debit rate rider from $0.099/GJ to $0.434/GJ to repay the GCVA balance to PNG (N.E.) over 2006; and
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ORDER NUMBER G -100-06 TELEPHONE: (604) 660-4700 BC TOLL FREE: 1-800-663-1385 FACSIMILE: (604) 660-1102
BRITISH COLUMBIA UTILITIES COMMISSION
ORDER NUMBER G-100-06 2
E. The Report also projected a credit balance of $118,000 in the Tumbler Ridge GCVA at December 31, 2005, which the current GCVA credit rate rider of $0.350/GJ will repay to customers over approximately 2.4 years; and
F. PNG (N.E.) had discussions regarding the review process for the Application with the BC Old Age Pensioners Organization et al. (“BCOAPO”) and staff of the Ministry of Energy, Mines and Petroleum Resources (“Ministry staff”), who were active intervenors in the review of the PNG 2005 revenue requirements application (the “Parties”). By letter dated December 13, 2005 PNG advised the Commission that the Parties were of the view that the Application should be subject to a Negotiated Settlement Process (“NSP”); and
G. Commission Order No. G-135-05 approved the interim refundable rate increase in the delivery charges for all rate classes of customers as filed in the Application, the permanent Gas Supply Cost Recovery Rates, the permanent Fort St. John/Dawson Creek Division debit GCVA rate rider and the continuation of the permanent Tumbler Ridge Division credit GCVA rate rider, all effective January 1, 2006; and
H. Commission Order No. G-135-05 also established an NSP for the review of the Application; and I. The Negotiated Settlement discussions were held in Vancouver on March 13, 14 and 15, 2006 and a proposed Settlement Agreement regarding the Application was agreed to by PNG (N.E.) and the Intervenors; and
J. In a letter of comment submitted on March 29, 2006 regarding the PNG-West Division 2006 Revenue Requirements NSP, BCOAPO did not accept the proposed PNG-West Settlement Agreement. BCOAPO objected to Item 1 of the proposed PNG-West Settlement Agreement and claimed that its objection would fundamentally change the overall 2006 cost of service for PNG-West. Changes in the PNG-West 2006 cost of service may impact the allocation of shared costs from PNG-West to PNG (N.E.); and
K. The Commission received submissions on the proposed PNG-West Settlement Agreement and other filings by PNG-West and Intervenors; and
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BRITISH COLUMBIA UTILITIES COMMISSION
ORDER NUMBER G-100-06 3
L. By Order No. G-99-06 with Reasons attached, the Commission issued its determination on the PNG-West 2006 Revenue Requirements Application; and
M. The Commission has reviewed the proposed Settlement Agreement for PNG (N.E.) and considers that approval is warranted.
NOW THEREFORE pursuant to sections 58, 60 and 61 of the Act, the Commission orders as follows: 1. The Commission approves for PNG (N.E.) the Negotiated Settlement Agreement attached as Appendix A, the Terms of the Negotiated Settlement Agreement along with the supporting schedules showing the effects of the changes arising from the Negotiated Settlement Agreement.
2. Since the approved rates are less than the interim rates which have been in effect since January 1, 2006, PNG (N.E.) is to inform its customers of the final rates by way of a customer notice and provide a method for refunding excess payments back to customers.
3. PNG (N.E.) is to file permanent Gas Tariff Rate Schedules that are in accordance with the terms of the Settlement and this Order.
4. PNG (N.E.) is to file a complete set of regulatory schedules in the form of the February 17, 2006 Update by September 8, 2006.
DATED at the City of Vancouver, in the Province of British Columbia, this 21 st day of August 2006. BY ORDER Original signed by: L.A. Boychuk Panel Chair & Commissioner Attachment
Orders/G-99-06_PNG(NE)_2006RR Settlement
APPENDIX A to Order No. G-100-06 Page 1 of 47
WILI.IAM J GRANT TR4NSITIO% \DL ISOR, AFr41RS RkGUL4TORY & PLA\\ING bill g~antQbcticL orn ~ e sbite http i iwi! w bcuc coiri
Log No. 12701 VIA E-MAIL March 3 1. 2006
Registered Intervenors (PNGNE-2006RR-RI) Pacific Nortl~ernG as - 2006 Revenue Requirements
Dear Registered Intervenors: Re: Pacific Northern Gas (N.E.) Ltd. ["PNG(N.E.)"] Fort St. Jolin/Dawson Creek and Tumbler Ridge Divisions Negotiated Settlements 2006 Revenue Requirements Application
Enclosed with this letter is the proposed settlement package for PNG(N.E.)'s 2006 Revenue Requirements Application for the Fort St. JohnlDawson Creek and Tumbler Ridge Divisions,
This settlement package is now public and is being submitted to the Comlnission and all Intervenors. Also enclosed are Letters of Acceptance from the participants in the negotiated settlement process. The Letter of Acceptance from PNG (N.E.) explains tlie revised regulatory schedules that are attached to the settlement
agreement.
Prior to consideration by tlie Commission, Intervenors who did not participate in the settlement negotiations u i l l be requested to provide to the Comn1issioi1 with their comments on the settlement package by Tl~i~rsdaAy.p ril 6. 2006. Thereafter. the Commission will consider the settlement package. A public hearing lnay not be required unless there is significant opposition to the proposed settlements.
Yours truly,
William J. Grant PU'aidlf Attachmeaits cc: Mr. Craig Donol~ue Director. Regulatory Affairs and Gas Supply Pacific Nortl-rern Gas (N,E.) Ltd.
P~~P".iGNE;_2006RR/GeCn oriPNG (YE) - NSP Letter to inter\enors
SIXTH FLOOR 900 tIOW E S1 R E t T ROY 2 5 0 V4VCOUVER B C C 4 V A D \ \ 6/ 2 \ 1 TELEPHONL I 604) 660-4700 BC TOLL FREE 1-800-663-11 85 FACSIMILE (6041 660-1 102
CONFIDENTIAL Pacific Northern Gas (N.E.) Ltd. (Tumbler Ridge Division)
2006 Revenue Requirements Application NEGOTIATED SETTLEMENT AGREEMENT March 15, 2006 Introduction PNG(N.E.) representatives, Commission Staff and registered intervenors met on March 13, 14 and 15, 2006 for the purpose of negotiating a settlement of PNG(N.E.)’s Tumbler Ridge division 2006 revenue requirements application. For ease of reference PNG(N.E.) will be referred to in this settlement agreement as PNG except where necessary to differentiate between PNG and PNG(N.E.). The following sets out the agreement reached on March 15, 2006 among the parties that participated in the negotiated settlement process.
For reference purposes herein, the original 2006 revenue requirements application dated November 30, 2005 will be referred to as the “Original Application”. The February 17, 2006 update to the Original Application will be referred to as the “Feb. 17’06 Update” and the March 9, 2006 update to the Feb. 17’06 Update will be referred to as the “Mar. 9’06 Update”.
1. Company Use Gas Forecast and Estimated Annual Cost The average actual annual plant fuel and lineheater use over the 2003 to 2005 period was 60,515 GJ. The parties agree to use the 60,515 GJ figure with an unaccounted for gas provision equal to zero subject to the implementation of a deferral account, for 2006 only, to record the extent to which actual unaccounted for gas volumes vary from zero. The resulting figures are as follows:
• PNG share of plant fuel and lineheaters – • CNRL share of plant fuel – • Unaccounted for gas - Totals 60,515 GJ or 9.03 % of deliveries
The projected 2006 Company use gas cost for rate making purposes will be based on actual prices applicable over the January to March 2006 period and the March 15, 2006 forward gas prices for the April to December 2006 period. This reduces the interim Company use gas rate of $1.403/GJ to a permanent rate of $0.635/GJ, effective January 1, 2006.
APPENDIX A to Order No. G-100-06 Page 2 of 47
12,194 GJ or 1.82 % of deliveries 48,321 GJ or 7.21 % of deliveries 0 GJ or 0% of deliveries
CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 3 of 47 2. Operating and Maintenance Expenses The 2006 budgeted operating and maintenance expenses, as set out in the regulatory schedules attached hereto, are accepted by the parties. The attached reflects the impact of PNG agreeing to reduce its 2006 forecast bad debt expense from $5,000 in the Original Application to $2,000 under this settlement agreement.
3. Administrative and General Expenses The 2006 budgeted administrative and general expenses, as set out in the regulatory schedules attached hereto, are accepted by the parties. The attached includes the impact of PNG agreeing to remove employee bonuses from pensionable earnings in 2006 for the purpose of calculating pension benefits costs. This was agreed to in recognition of the Commission’s direction to Terasen Gas to do so in an earlier proceeding. PNG’s agreement to voluntarily comply with this direction is being made without prejudice to its right to make submissions to the Commission in future revenue requirements applications to allow PNG to include bonuses in pensionable earnings.
4. Benefits Surcharge under Shared Services from PNG to PNG(N.E.) The benefits surcharge has decreased from 36.3 percent to 35.1 percent as a result of the parent company reducing its pension costs.
5. Account 721 Shared Services from PNG to PNG(N.E.) Pension benefits costs are reduced due to the parent company reducing its pension costs.
6. Account 728 Shared Services from PNG to PNG(N.E.) If PNG(N.E.) was a reporting issuer a conservative estimate of its Account 728 costs is $180,000 for fiscal and corporate expenses and $200,000 for directors fees and expenses. Hence, the parties agree that a total charge of only $87,000 (i.e. $84,000 for the FSJ/DC division and $3,000 for the Tumbler Ridge division) from PNG to PNG(N.E.) for Account 728 services is reasonable and is accepted by the parties. For greater clarity, these costs are not incremental to the provision of $7,000 under Account 728 for fiscal and corporate expense at Tab 1, Tumbler Ridge, page 5 of the Original Application because the $7,000 figure is only for the Tumbler Ridge division share of B.C. Utilities Commission administrative costs and a small provision for donations to the Tumbler Ridge service area. The schedule at Tab 1, Tumbler Ridge, page 5 will be modified to more clearly identify the breakdown of the total Account 728 costs of $10,000 for the Tumbler Ridge division.
CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 4 of 47
7. Account 685 Shared Services Charges from PNG to PNG(N.E.) Account 685 captures a wide range of activities including payroll, accounts payable, warehousing and technical services provided in Terrace. Fixed plant accounting is not a major component of Account 685. As a result, the level of costs in Account 685 reflects levels of activity not levels of assets. Key drivers of Account 685 costs are operating costs and capital expenditures, which are largely determinative of payroll, accounts payable activity, warehousing and technical services. The parties agree that employee count is a reasonable proxy for these drivers.
8. Amortization Expense The 2005 plant upset deferral account is accepted as applied for by PNG. 9. Capital Additions The 2006 capital additions forecast contained in the Feb. 17’06 Update is accepted by the parties including the provision for the above ground double walled waste water containment vessel at the Tumbler Ridge processing plant.
10. Gas Deliveries Forecast The 2006 gas deliveries forecast for all customer classes as set out in the Feb. 17’06 Update is accepted by the parties with the exception of CNRL where the 2006 forecast will be increased from 500,000 GJ to 533,700 GJ.
11. RSAM-Revenue Stabilization Adjustment Mechanism Rate Rider for 2006 The RSAM rider applicable to residential and small commercial customers in 2006 is accepted at $0.531/GJ. A Table is attached showing the calculation of the 2006 RSAM rate rider, effective January 1, 2006.
12. Return on Equity and Capital Structure The adjustments to the return on equity component of the cost of service set forth in the Mar. 9’06 Update are accepted by the parties. This is based on increasing the allowed return on equity from 8.94 percent in the Original Application to 9.45 percent in the Mar. 9’06 Update to reflect the impact of the Commission’s 51 basis points increase to the return on equity for a benchmark low-risk utility. The 36 percent deemed common equity in the capital structure is accepted by the parties for rate making purposes in 2006.
CONFIDENTIAL 13. Lump Sum Settlement Allowance With a view to settling the 2006 revenue requirements application and thereby avoiding the cost of a public hearing, a 2006 settlement allowance reduction of $2,000 is accepted by the parties.
14. Commission Staff Issues List The Commission Staff prepared an issues list to facilitate the negotiated settlement process. Attached for reference is a copy of the Commission Staff issues list.
15. Regulatory Financial Schedules Attached are the following regulatory financial schedules to document the NSP 2006 settlement of the 2006 PNG(N.E.) Tumbler Ridge division revenue requirements application.
• NSP 2006 to Mar. 9’06 Update Cost of Service Comparison Table to show the changes made to the Mar. 9’06 Update to achieve the 2006 negotiated settlement.
• NSP 2006 vs. NSP 2005 Cost of Service Comparison Table • Bill Comparison Table comparing residential and small commercial customer rates effective December 31, 2005 to NSP 2006 rates effective January 1, 2006.
• Bill Comparison Table comparing NSP 2006 residential and small commercial customer rates effective January 1, 2006 to proposed rates effective April 1, 2006 that reflect the NSP delivery charge rates in conjunction with proposed gas supply commodity changes effective April 1, 2006.
• Regulatory Schedules 1 to 5 showing the NSP 2006 and Mar. 9’06 Update figures in conjunction with the corresponding Actual 2005 figures.
It is noted that the cost of sales figure for NSP 2006 at Tab 1, Utility Income & Return, Schedule 1, line 16 is based on the November 28, 2005 forward gas price strip. The Company use gas cost forecast for NSP 2006 is based on the March 15, 2006 forward gas price strip. These items are also reflected in the Bill Comparison Table December 2005 to January 2006.
The parties noted that the Bill Comparison Table for the NSP January 1, 2006 to proposed April 1, 2006 rates comparison showed a significant impact from the proposed gas supply cost reduction effective April 1, 2006. The observation was made that the proposed rates effective April 1, 2006 were less than the rates that prevailed at the end of 2005.
APPENDIX A to Order No. G-100-06 Page 5 of 47
CONFIDENTIAL Upon Commission approval of this settlement agreement PNG agrees to file, as an exhibit to these proceedings, a complete set of regulatory schedules in the form of the Feb 17’06 Update to document the negotiated settlement to the same level of detail as set forth in the Original Application.
APPENDIX A to Order No. G-100-06 Page 6 of 47
CONFIDENTIAL PACIFIC NORTHERN GAS (N.E.) LTD (Tumbler Ridge Division) 2006 Revenue Requirements Application B.C. Utilities Commission Staff Prepared Issues List Issues Operating Costs 1. Operating Costs Excluding Company Use Gas increased by $15,000 Processing Plant – Account 621 increased by $35,000 - Increase in contractor charges $10,000 - Standby charges of $18,000 transferred from account 685
- Telecommunications and license expense increase of $5,000
2. Company Use Gas increased by $94,245 B-1, Tab Application TR, p. 16 $28,867 of increase - 37% increase in commodity B-8, Tab 1 TR (Rev.), p. 3 cost $65,378 of increase - 61% increase in volumes
3. Cost transfers From Account 677 to Account 667, total cost increase of $2,000
From Account 685 to Account 670, total cost decrease of $21,000
4. Other General Operation- Account 688, decreased by $11,000 5. Uncollectible Accounts – Account 718, increased by $1,000, an 25% increase
APPENDIX A to Order No. G-100-06 Page 7 of 47 References B-1, Tab Application TR, p. 5 B-8, Tab Application TR (Rev.), p. 3 B-8, Tab Application TR (Rev.), p. 3 B-1, Tab Application TR, p. 6
B-1, Tab Application TR, pp. 6-7 B-8, Tab 1 TR (Rev.), p. 3
B-1, Tab Application TR, p. 7 B-8, Tab 1 TR (Rev.), p. 3 B-8, Tab 1 TR (Rev.), p. 3
CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 8 of 47
Issues Maintenance Costs 6. Maintenance Costs increased by $2,000 An increase of less than 5% Administrative and General Costs 7. Insurance – Account 723, decreased by $3,000 Change in insurance coverage GCVA to cover interruption losses 8. Employee benefits - Account 725, increased by $3,000
Shared Service Charges by PNG to PNG(N.E.) TR 9. Benefits surcharge appears to increase B-1, Tab Application TR, p. 9 from 32.3% to 36.2%
- Additional increase noted, B-8, Tab 1 TR (Rev.), p. 5 but the percentage increase was not provided
10. Total shared service costs have increased by $16,000 This represents a 16.7% cost increase 11. Shared service allocation factors Account 685 - Accounts payables processing, plant accounting and warehouse technical services allocated on employee count 12. System Operations Shared Service from Parent – Account 685 increased by $2,000
13. Customer Care costs increased by $3,000 B-8, Tab 1 TR (Rev.), p. 3 Customer billing- Account 713 increased by $3,000 14. Administration Shared Service from B-1, Tab Application TR, p. 9 Parent - Account 721, increased by $8,000
15. New allocated costs of $3,000 for Fiscal and corporate expense Shared Service from Parent – Account 728 7
References B-1, Tab Application TR, p. 6 B-8, Tab 1 TR (Rev.), p. 4 B-1, Tab Application TR, p. 8 B-1, Tab Application TR, p. 8 B-8, Tab 1 TR (Rev.), p. 5 B-1, Tab Application TR, p. 7
B-1, Tab Application TR, pp. 10-11 B-8, Tab 1 TR (Rev.), p. 5 B-1, Tab Application TR, p. 11 B-10, Response to BCUC IR FSJ/DC, Questions 42.1 – 42.4, pp. 8-10 B-8, Tab 1 TR (Rev.), p. 3
B-8, Tab 1 TR (Rev.), p. 5 B-1, Tab Application TR, p. 9 B-8, Tab 1 TR (Rev.), p. 5
CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 9 of 47
Issues 16. Transfers to Capital - $9,000 Increase in capitalization rate to 3.5% 17. Property Taxes - $38,000 Same as Decision 2005 18. Depreciation – $163,000 Increased by $18,000 19. Amortization Tumbler Ridge Plant Upset Deferral$172,385
20. Other Income - $8,000 $5,000 decrease - Sale of rental house 21. Income Taxes - $67,000 22. Return on Common Equity ROE of 9.45% reflects Commission Order G-14-06 23. Capital Structure – 36% Equity Same as Decision 2005 24. Long term loan of $0.15 million from PNG 25. Interest Expense - $63,000 26. Capital Additions increased by $31,000 Waste water containment vessel 27. Load Forecast TR Residential – 79,245 GJ Small Commercial – 30,004 GJ Large Commercial – 21,000 GJ Industrial Transportation –500,000 GJ 28. RSAM Rate Riders 29. Gas Supply Cost Charge Changes/GCVA Riders 2005 Fourth Quarter Gas Supply Cost Report 30. Emergency response time 3 calls with response times > 40 min. 8
References B-1, Tab Application TR, p. 11 B-8, Tab 1 TR (Rev.), p. 2 B-1, Tab Application TR, p. 11 B-8, Tab 1 TR (Rev.), p. 6 B-1, Tab Application TR, p. 12 B-8, Tab 2 TR (Rev.), p. 4 B-1, Tab Application TR, p. 12 B-8, Tab 2 TR (Rev.), p. 7 B-3, Response to BCUC IR 34.1 Commission Order G-122-05
B-1, Tab Application TR, p. 12 B-8, Tab 1 TR (Rev.), p. 7 B-13, Application (Rev.), p. 3 B-1, Tab Application TR, p. 13 B-13, Application (Rev.), p. 1 B-1, Tab Application TR, p. 13 B-1, Tab Application TR, pp. 13-14 B-8, Tab 3 TR (Rev.), p. 1 B-1, Tab Application TR, p. 15 B-1, Tab Application TR, p. 16 B-8, Tab 2 TR (Rev.), p. 1 B-1, Tab Application TR, p. 17 B-1, Tab Application TR, p. 21 B-1, Tab Application TR, pp. 21-22 B-3, Response to BCUC IR TR, Question 38.2, p. 60
CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 10 of 47 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division) 2006 Revenue Requirements Application NEGOTIATED SETTLEMENT AGREEMENT March 15, 2006 Introduction PNG(N.E.) representatives, Commission Staff and registered intervenors met on March 13, 14 and 15, 2006 for the purpose of negotiating a settlement of PNG(N.E.)’s Fort St. John/Dawson Creek (FSJ/DC) division 2006 revenue requirements application. For ease of reference PNG(N.E.) will be referred to in this settlement agreement as PNG except where necessary to differentiate between PNG and PNG(N.E.). The following sets out the agreement reached on March 15, 2006 among the parties that participated in the negotiated settlement process.
For reference purposes herein, the original 2006 revenue requirements application dated November 30, 2005 will be referred to as the “Original Application”. The February 17, 2006 update to the Original Application will be referred to as the “Feb. 17’06 Update” and the March 9, 2006 update to the Feb. 17’06 Update will be referred to as the “Mar. 9’06 Update”.
1. Operating and Maintenance Expenses The 2006 budgeted operating and maintenance expenses, as set out in the regulatory schedules attached hereto, are accepted by the parties. The attached reflects the impact of PNG agreeing to assume a bad debt expense factor of 0.5 percent to calculate the 2006 budgeted allowance for bad debt. PNG will review its collection policies and submit a report to the Commission on initiatives to be taken by PNG to reduce bad debt over time. The report will be filed on or before July 1, 2006.
CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 11 of 47
2. Company Use Gas Forecast and Estimated Annual Cost PNG agrees to set its 2006 provision Company use gas requirements at 1.11 percent of forecast gas deliveries subject to the implementation of a deferral account, for 2006 only, to record the extent to which actual unaccounted for gas volumes vary from the forecast. The unaccounted for gas volume is equal to the difference between 1.11 percent of forecast volumes and the provision for lineheaters, office, blowdowns and losses based on the average of actual figures for the 2001 to 2005 five year period. The resulting figures are as follows:
• Lineheaters and office – 15,133 GJ or 0.32 % of deliveries • Blowdowns and losses – 4,819 GJ or 0.10 % of deliveries • Unaccounted for gas – 33,272 GJ or 0.69 % of deliveries Totals 53,224 GJ or 1.11 % of deliveries
The projected 2006 Company use gas cost for rate making purposes will be based on actual prices applicable over the January to March 2006 period and the March 15, 2006 forward gas prices for the April to December 2006 period. This reduces the interim Company use gas rate of $0.15/GJ to a permanent rate of $0.087/GJ, effective January 1, 2006.
3. Administrative and General Expenses The 2006 budgeted administrative and general expenses, as set out in the regulatory schedules attached hereto, are accepted by the parties. The attached includes the impact of PNG agreeing to remove employee bonuses from pensionable earnings in 2006 for the purpose of calculating pension benefits costs. This was agreed to in recognition of the Commission’s direction to Terasen Gas to do so in an earlier proceeding. PNG’s agreement to voluntarily comply with this direction is being made without prejudice to its right to make submissions to the Commission in future revenue requirements applications to allow PNG to include bonuses in pensionable earnings.
4. Benefits Surcharge under Shared Services from PNG to PNG(N.E.) The benefits surcharge has decreased from 36.3 percent to 35.1 percent as a result of the parent company reducing its pension costs.
5. Account 721 Shared Services from PNG to PNG(N.E.) Pension benefits costs are reduced due to the parent company reducing its pension costs.
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CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 12 of 47
6. Account 728 Shared Services from PNG to PNG(N.E.) If PNG(N.E.) was a reporting issuer a conservative estimate of its Account 728 costs is $180,000 for fiscal and corporate expenses and $200,000 for directors fees and expenses. Hence, the parties agree that a total charge of only $87,000 (i.e. $84,000 for the FSJ/DC division and $3,000 for the Tumbler Ridge division) from PNG to PNG(N.E.) for Account 728 services is reasonable and is accepted by the parties. For greater clarity, these costs are not incremental to the provision of $49,000 under Account 728 for fiscal and corporate expense at Tab 1, FSJ/DC, page 5 of the Original Application because the $49,000 figure is only for the FSJ/DC division share of B.C. Utilities Commission administrative costs and a small provision for donations to the FSJ/DC service area. The schedule at Tab 1, FSJ/DC, page 5 will be modified to show the breakdown of the total Account 728 costs of $133,000 for the FSJ/DC division into the fiscal and corporate costs from PNG, the Commission costs and donations segments.
7. Account 685 Shared Services Charges from PNG to PNG(N.E.) Account 685 captures a wide range of activities including payroll, accounts payable, warehousing and technical services provided in Terrace. Fixed plant accounting is not a major component of Account 685. As a result, the level of costs in Account 685 reflects levels of activity not levels of assets. Key drivers of Account 685 costs are operating costs and capital expenditures, which are largely determinative of payroll, accounts payable activity, warehousing and technical services. The parties agree that employee count is a reasonable proxy for these drivers.
8. Gas Deliveries Forecast The 2006 gas deliveries forecast for all customer classes as set out in the Feb. 17’06 Update is accepted by the parties.
9. RSAM-Revenue Stabilization Adjustment Mechanism Rate Rider for 2006 The RSAM rider applicable to residential and small commercial customers in 2006 is accepted at $0.114/GJ. A Table is attached showing the calculation of the 2006 RSAM rate rider, effective January 1, 2006.
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CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 13 of 47
10. Return on Equity and Capital Structure The adjustments to the return on equity component of the cost of service set forth in the Mar. 9’06 Update are accepted by the parties. This is based on increasing the allowed return on equity from 8.69 percent in the Original Application to 9.20 percent in the Mar. 9’06 Update to reflect the impact of the Commission’s 51 basis points increase to the return on equity for a benchmark low-risk utility. The 36 percent deemed common equity in the capital structure is accepted by the parties for rate making purposes in 2006.
11. Tracking of Customer Complaints PNG will attempt to keep a record of customer complaints received from the FSJ/DC division customers in 2006 and prepare a report to the Commission summarizing the results. The report will contain a discussion of whether it would be useful for PNG to continue tracking complaints in 2007 and beyond.
12. Lump Sum Settlement Allowance With a view to settling the 2006 revenue requirements application and thereby avoiding the cost of a public hearing, a 2006 settlement allowance reduction of $50,000 is accepted by the parties.
13. Commission Staff Issues List The Commission Staff prepared an issues list to facilitate the negotiated settlement process. Attached for reference purposes is a copy of the Commission Staff issues list.
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CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 14 of 47
14. Regulatory Financial Schedules Attached are the following regulatory financial schedules to document the NSP 2006 settlement of the 2006 PNG(N.E.) FSJ/DC division revenue requirements application.
• NSP 2006 to Mar. 9’06 Update Cost of Service Comparison Table to show the changes made to the Mar. 9’06 Update to achieve the 2006 negotiated settlement.
• NSP 2006 vs. NSP 2005 Cost of Service Comparison Table • Bill Comparison Table comparing residential and small commercial customer rates effective December 31, 2005 to NSP 2006 rates effective January 1, 2006.
• Bill Comparison Table comparing NSP 2006 residential and small commercial customer rates effective January 1, 2006 to proposed rates effective April 1, 2006 that reflect the NSP 2006 delivery charge rates in conjunction with PNG’s proposed gas supply commodity rate changes effective April 1, 2006.
• Regulatory Schedules 1 to 5 showing the NSP 2006 and Mar. 9’06 Update figures in conjunction with the corresponding Actual 2005 figures.
It is noted that the cost of sales figure for NSP 2006 at Tab 1, Utility Income & Return, Schedule 1, line 16 is based on the November 28, 2005 forward gas price strip. The change in the cost of sales from the March 9’06 Update to the NSP 2006 figure reflects a correction to PNG’s gas cost flow through model and does not affect the Commission approved permanent gas supply commodity rates effective January 1, 2006. The Company use gas cost forecast for NSP 2006 is based on the March 15, 2006 forward gas price strip. These items are also reflected in the Bill Comparison Table December 2005 to January 2006.
The parties noted that the Bill Comparison Table for the NSP January 1, 2006 to proposed April 1, 2006 rates comparison showed a significant impact from the proposed gas supply cost reduction effective April 1, 2006. The observation was made that the proposed rates effective April 1, 2006 were less than the rates that prevailed at the end of 2005.
Upon Commission approval of this settlement agreement PNG agrees to file, as an exhibit to these proceedings, a complete set of regulatory schedules in the form of the Feb 17’06 Update to document the negotiated settlement to the same level of detail as set forth in the Original Application.
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CONFIDENTIAL PACIFIC NORTHERN GAS (N.E.) LTD. (Fort St. John/Dawson Creek Division) 2006 Revenue Requirements Application B.C. Utilities Commission Staff Prepared Issues List Issues Operating Costs 1. Labour cost increase of $94,000 IBEW contract increases - $55,000 Higher standby charges - $5,000 Other Increases - $34,000 2. Company Use Gas increased by $474,000
$397,943 of increase - higher B-9, Tab 1 FSJ/DC (Rev.), p. 3 volumes of 43,025 GJ
$89,618 of increase - 40% increase in commodity cost
3. Cost transfers B-1, Tab Application FSJ/DC, pp. 6-7 From Account 677 to Account 667, total cost increase of $6,000
From Account 685 to Account 670, total cost increase of $30,000
4. Other General Operation- Account 688, B-1, Tab Application FSJ/DC, p. 7 increased by $59,000
Reallocation of vehicle costs $30,000 B-9, Tab 1 FSJ/DC (Rev.), p. 3 Overtime vacation pay $7,000 Labour cost increase $17,000 5. Uncollectible Accounts – Account 718, B-1, Tab Application FSJ/DC, p. 7 increased by $104,000
Actual 2005 Bad Debt Factor of 0.63% B-3, , Response to BCUC IR FSJ/DC, used to forecast 2006 Questions 5.1 – 5.3, pp. 4 - 5 5-year average actual Bad Debt Factor of 0.46%
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APPENDIX A to Order No. G-100-06 Page 15 of 47 References B-1, Tab Application FSJ/DC, p. 5 B-1, Tab Application FSJ/DC, p. 6 B-1, Tab Application FSJ/DC, p. 16
CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 16 of 47
Issues References Maintenance Costs 6. Maintenance Costs decreased by B-1, Tab Application FSJ/DC, p. 7 $25,000
Administrative and General Costs 7. Insurance – Account 723, decreased by $19,000
Change in insurance coverage B-9, Tab 1 FSJ/DC (Rev.), p. 5 GCVA to cover interruption losses 8. Employee benefits - Account 725, B-1, Tab Application FSJ/DC, p. 8 increased by $50,000
B-9, Tab 1 FSJ/DC (Rev.), p. 5 Shared Service Charges by PNG to PNG(N.E.)
9. Benefits surcharge appear to be B-1, Tab Application FSJ/DC, p. 10 increased from 32.3% to 36.3%
Additional increase noted, but the B-9, Application 1 FSJ/DC (Rev.), p. 2 percentage increase was not provided
10. Total shared service costs have B-1, Tab Application FSJ/DC, pp. 10-11 increased by $299,000
This represents a 24.6% cost increase B-9, Tab 1 FSJ/DC (Rev.), p. 5 B-9, Tab 1 FSJ/DC (Rev.), p. 3
11. System Operations Shared Service from Parent – Account 685 increased by $52,000
12. Customer Care costs increased by B-9, Tab 1 FSJ/DC (Rev.), p. 3 $53,000
Customer contracts - Account 711 B-6, p Response to PRRD IR FSJ/DC, decreased by $1,000 Questions 9.1 and 9.2, p. 6 Customer billing- Account 713 increased by $54,000
Credit and collections - Account 714 decreased by $5,000
Meter reading - Account 712 increased by $1,000
7
B-1, Tab Application FSJ/DC, p. 8 B-1, Tab Application FSJ/DC, p. 8
CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 17 of 47
Issues 13. Administration Shared Service from Parent - Account 721, increased by $115,000 14. New allocated costs of $84,000 for Fiscal and corporate expense Shared Service from Parent – Account 728 15. Shared service allocation factors Account 685 - Accounts payable processing, plant accounting and warehouse technical services allocated on employee count
16. Transfers to Capital 17. Property Taxes 18. Depreciation 19. Amortization 20. Other Income 21. Income Taxes 22. Return on Common Equity 23. Capital Structure 24. Long term loan of $7.85 million from PNG 25. Interest Expense 26. Capital Additions 27. Load Forecast FSJ Residential – 1,103,434 GJ Small Commercial – 811,065 GJ Large Commercial – 165,102 GJ Small Industrial Sales – 308,439 GJ Small Industrial T-Service – 1,072, 559
8
References B-1, Tab Application FSJ/DC, p. 10 B-9, Tab 1 FSJ/DC (Rev.), p. 5 B-1, Tab Application FSJ/DC, p. 10 B-9, Tab 1 FSJ/DC (Rev.), p. 5 B-1, Tab Application FSJ/DC, p. 11 B-10, Response to BCUC IR FSJ/DC, Questions 42.1 – 42.4, p. 59
B-9, Tab 1 FSJ/DC (Rev.), p. 2 B-9, Tab 1 FSJ/DC (Rev.), p. 1 B-9, Tab 1 FSJ/DC (Rev.), p. 1 B-9, Tab 1 FSJ/DC (Rev.), p. 1 B-9, Tab 1 FSJ/DC (Rev.), p. 1 B-9, Tab 3 FSJ/DC (Rev.), p. 1 B-9, Tab 5 FSJ/DC (Rev.), p. 1 B-9, Tab 5 FSJ/DC (Rev.), p. 1 B-1, Tab Application FSJ/DC, pp. 14-16 B-9, Tab 5 FSJ/DC (Rev.), p. 1 B-9, Tab 2 FSJ/DC (Rev.), p. 1 B-9, Tab Rates FSJ/DC, p.10
CONFIDENTIAL APPENDIX A to Order No. G-100-06 Page 18 of 47
Issues References 28. Load Forecast DC B-9, Tab Rates FSJ/DC, p.10 Residential – 620,742 GJ Small Commercial – 485,979 GJ Large Commercial – 151,998 GJ Small Industrial Sales- 75,660 GJ 29. RSAM Rate Riders B-1, Tab Application FSJ/DC, p. 23 30. Gas Supply Cost Charge B-3, Response to BCUC IR FSJ/DC, Changes/GCVA Riders Question 39.6, p. 69 - 2005 Fourth Quarter Gas Supply Cost Report
- Legal fees associated with Samson Supreme Court action treated as a GCVA cost
31. Emergency response time - 37 calls with response times > 40 min 32. Declining Customer Service 9
B-3, Response to BCUC IR FSJ/DC, Question 37.1, p. 59 B-6, Response to PRRD IR FSJ/DC, Question 9.1, p.6
APPENDIX A to Order No. G-100-06 Page 19 of 47
The Richard J.G athercole British Columbia Sarah Khan Public Interest Patricia BVlacDonaid James L. Quail Advocacy Centre Leigha VVorth 208-1090 West Pender Street Barristers B Solicitors Vancouver, BC V6E 2N7 Tel: (604) 687-3063 Fax: (604) 682-7896 Valerie Conrad email: bcoiac@bcpiac.com htt~:llwww.bcoiac.com Articled S t u d e n t March 29,2006 VIA E-MAIL AND MAIL William J. Grant Transition Advisor Regulatory Affairs & Planning I36 Utilities Comission Sixth Floor - 900 H o w Street Vancouver, BC V6Z 2M3 Re: BNG W.E.) ktd, Ft St. JohnDawson Creek and Tumbler Ridge Divisions Negotiated Settlement 2006 Revenue Requirements Appliea~orr
I act for BC Old Age Pensioners' Organization, Active Support Against Poverly, Councif of Senior Citizens' Organizations, federated anti-poverly groups of Be,E nd Legislated Poverty, and Coalition of People with Disabilities (collectively h o w a s BCOAPO).
BCOAPO confims its acceptance of these sefilemenls. BCOAPO is aware, given the relationship between PNG-West and PNG W.E.), that Ihe latter's revenue requirement may be impacted by the resolution of the issue raised by BCOAPO w& respect to the PNG-West proposed Negotiated Settlement.
Yours sincerely, BG PUBLIC INTEmST ADVOCACY CENT=
'~xecutiveD irector c : Craig Donohue
APPENDIX A to Order No. G-100-06 Page 20 of 47
DONOVAN & COMPAW Barristers and Solicitors 6" Floor, 73 Water Street Vancouver, B.G. V6B 1Al Telephone (604) 688-4272 Telecopier (S04) 688-4282 .aboriginal-law.wm
VIA EMAIL B.G. Utilities Commission Box 250,900 Wowe Street Sidk Floor Vancouver, BG V6Z 2N3
Dear Mr. Grant: Re:: Paclfiic Nodhern Gas Ltd. (N.E.) (""IPNG-NE"") Negotiated Senlennsnl Agreement
W e have reviewed the final Negotiated SeMlernen'r Agreement fo"rJrNG-NE's 2006 Revenue Requirements Application. The Haisia Nation lakes no position on the Agreement.
Yours truly,
66: Chief Steve Wilson and Council, Haisla Nation CG: Mr. Craig Donohue Diredor, Regulatory AFFairs and Gas Supply, Pacific Nodhern Gas Ltd.
Mian Donovan* Menill W. Shepard? Susan J. Alcatt+* Xarim Ramji* Sophia Nishimoto Myriarn Brulol Jennifer Gfm~Vt Bram Rogaehevsky Courtney Maciarlane
APPENDIX A to Order No. G-100-06 Page 21 of 47
Craig P. Donohue Director, Regulatory Affairs & Gas Supply Via E-Mail and Courier March 30, 2006 B.C. Utilities Commission 6th Floor - 900 Howe Street Vancouver, B.C. V6Z 2N3
Attention: William J. Grant Transition Advisor Regulatory Affairs & Planning
Dear Sir: Re: PNG(N.E.) Negotiated Settlements for the Fort St. John/Dawson Creek and Tumbler Ridge Divisions’ 2006 Revenue Requirements Applications
Further to your letter dated March 28, 2006 enclosing the Negotiated Settlement Agreements for the PNG(N.E.) Fort. St. John/Dawson Creek and Tumbler Ridge Divisions’ 2006 Revenue Requirements Application, along with supporting documents, PNG hereby confirms its acceptance of the settlements subject to the remarks below concerning the regulatory schedules attached to the settlement agreements.
Fort St. John/Dawson Creek Division The regulatory schedules attached to the settlement agreement distributed under cover of your letter dated March 28, 2006 showed a projected NSP 2006 revenue sufficiency of $52,000. Attached to this letter is a revised set of NSP 2006 regulatory schedules for the FSJ/DC division showing a slightly lower revenue sufficiency of $44,000. The reduction results from adjustments to the amortization expense calculation for 2006. In PNG’s response 41.0 to BCUC IR No. 2 for the FSJ/DC division, PNG advised that all of BCOAPO’s 2005 hearing costs award had been included in the PNG-West division when about 50 percent should have been allocated to PNG(N.E.). In the response PNG advised this adjustment would be made in the final 2006 schedules. Unfortunately, this adjustment was not made before the settlement schedules were prepared. The result of allocating a portion of the BCOAPO 2005 hearing costs to FSJ/DC is in an overall increase of $8,000 in the 2006 cost of service compared to the original NSP settlement schedules.
APPENDIX A to Order No. G-100-06 Page 22 of 47 Pacific Northern Gas Ltd. Suite 950 1185 West Georgia Street Vancouver, BC V6E 4E6 Tel: (604) 691-5673 Tel: (604) 697-6210 Email: cdonohue@png.ca File No.: 4.2.7 (2006)
2 APPENDIX A to Order No. G-100-06 Page 23 of 47 PNG understands that the Negotiated Settlement Agreement, the regulatory schedules attached thereto and letters of comment by the participants in the NSP 2006 meetings will be made public and forwarded to the Commission for its review on Friday, March 31, 2006. PNG requests that the enclosed settlement regulatory schedules be attached to the Negotiated Settlement Agreement that is made public and forwarded to the Commission in place of the schedules that were distributed with the draft settlement agreement. This will avoid confusion that may arise if the draft settlement regulatory schedules are distributed together with this letter of comment and the enclosed revised NSP 2006 settlement regulatory schedules. In addition, it is recommended that when this letter of comment is attached to the documents that are made public, that the attachment not be included assuming the attachment is made part of the Negotiated Settlement Agreement. When the Commission, non NSP participants and others read this letter of comment, they will have been properly advised of this slight change to the NSP 2006 settlement regulatory schedules accordingly.
Tumbler Ridge Division The revenue deficiency of $83,000 set forth in the Tumbler Ridge division settlement regulatory schedules distributed with the draft NSP 2006 settlement agreement has not changed as a result of PNG’s final review. PNG considered the hearing costs budget for 2006 in the Tumbler Ridge division was sufficient to cover the NSP 2006 settlement meetings and their share of the BCOAPO 2005 hearing costs. Hence, a change to the hearing costs amortization expense similar to that in the FSJ/DC division was not required in the Tumbler Ridge division. However, for completeness, enclosed is a set of the NSP 2006 settlement regulatory schedules that were printed at the same time as the FSJ/DC division revised schedules. PNG requests that the attached be used in the settlement agreement that is forwarded to the Commission, non NSP participants and others on Friday, March 31, 2006.
Please direct any questions regarding this letter to my attention. Yours truly,
C.P. Donohue cc. P. Nakoneshny
NSP 2006 Mar. 15 '06 APPENDIX A to Order No. G-100-06
Pacific Northern Gas (N.E.) Ltd. Page 24 of 47 (Tumbler Ridge Division)
NSP 2006 to Revised Mar. 9 '06 COST OF SERVICE COMPARISON ($000)
Revised NSP 2006 App. EXPENSES 2006 Mar. 9 '06 Difference Operating Labour 209 209 0 Other 279 282 (4) Sub-total 487 491 (4) Maintenance Labour 22 22 0 Other 39 39 0 Sub-total 62 62 0 Administrative and General Labour 0 0 0 Total Company Benefits 68 69 (1) Other 71 71 (0) Sub-total 139 140 (1) Total (O, M, A & G) Excluding Co. Use 688 693 (5) Transfers to Capital Operating (4) (4) 0 Transfers to Capital Admin. & Gen. (5) (5) 0 Property Taxes 38 38 0 Depreciation 163 163 0 Amortization 17 20 (4) Other Income (8) (8) 0 2006 Settlement Allowance (2) 0 (2) Total Expenses Excluding Co, Use 886 896 (11) Income Taxes 68 68 (0) Return on Common Equity 39 39 0 Short Term Debt 2 2 0 Long Term Debt 61 61 0 Preferred Shares 0 0 0 Total Cost of Service Excluding Co. Use 1056 1067 (11) Company Use Gas 87 185 Total Cost of Service Including Co. Use 1143 1252 2005 to 2006 Cost of Service Increase 55 66 (11) 2005 to 2006 Margin Decrease 28 45 (17) 2006 Revenue Deficiency 83 111 (28)
Pacific Northern Gas (N.E.) Ltd. (Tumbler Ridge Division) NSP 2006 vs. Decision 2005 COST OF SERVICE COMPARISON ($000)
NSP Decision Difference EXPENSES 2006 2005 Total Subtotal Operating Labour 209 227 (18) Other 279 250 29 Sub-total 487 476 11 Maintenance Labour 22 21 1 Other 39 39 1 Sub-total 62 60 2 Administrative and General Labour 0 0 0 Total Company Benefits 68 66 2 Other 71 64 7 Sub-total 139 130 10 Total (O, M, A & G) Excluding Co. Use 688 666 22 22 Transfers to Capital Operating (4) (5) 1 Transfers to Capital Admin. & Gen. (5) (3) (2) Property Taxes 38 38 (1) Depreciation 163 145 17 Amortization 17 14 3 Other Income (8) (13) 5 2006 Settlement Alowance (2) 0 (2) 22 Total Expenses Excluding Co, Use 886 841 44 44 Income Taxes 68 62 6 Return on Common Equity 39 37 2 Short Term Debt 2 2 0 Long Term Debt 61 58 3 Preferred Shares 0 0 0 11 Total Cost of Service Excluding Co. Use 1056 1001 55 55 Company Use Gas 87 86 Total Cost of Service Including Co. Use 1143 1087 2005 to 2006 Cost of Service Increase 55 2005 to 2006 Margin Decrease 28 2006 Revenue Deficiency 83
NSP 2006 Mar. 15 '06 APPENDIX A Tab Application to Order No. G-100-06 Tumbler Ridge 2006 Rate App. Page 25 of 47 Page 3
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Tab Rates FSJ/DC Page 26 of 47 2006 Rate App. Page 2
Pacific Northern Gas (N.E.) Ltd. (Tumbler Ridge Division)
Bill Comparison December 2005 to January 2006
Permanent Rates Annual Bill NSP Rates Annual Bill Annual Bill Customer Classification Dec. 31, 2005 Estimate Jan. 1, 2006 Estimate Difference Annual Use $ / GJ $ $ / GJ $ $ % Residential: 74.6 GJ Monthly Fixed Charge @ 8.50 / mo. 1.367 102.00 1.367 102.00 0.00 Delivery Charge 5.387 401.87 5.930 442.38 40.51 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.284 21.19 0.531 39.61 18.42 Interim Rate Refund Rider (0.135) (10.07) 0.000 0.00 10.07 514.99 583.99 69.00 13.4% Gas Supply Charge 8.753 652.97 8.822 658.12 5.15 GCVA Rider (0.350) (26.11) (0.350) (26.11) 0.00 626.86 632.01 5.15 0.8% $15.306 /GJ $1,141.85 $16.300 /GJ $1,216.00 $74.15 6.5% Small Commercial: 553.9 GJ Monthly Fixed Charge @ 8.50 / mo. 0.184 102.00 0.184 102.00 0.00 Delivery Charge 4.719 2,613.85 5.116 2,833.75 219.90 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.284 157.31 0.531 294.12 136.81 Interim Rate Refund Rider (0.083) (45.97) 0.000 0.00 45.97 2,827.19 3,229.87 402.69 14.2% Gas Supply Charge 8.753 4,848.29 8.822 4,886.51 38.22 GCVA Rider (0.350) (193.87) (0.350) (193.87) 0.00 4,654.42 4,692.64 38.22 0.8% $13.507 /GJ $7,481.61 $14.303 /GJ $7,922.51 $440.90 5.9% Billcomparisons-06 Effective Jan 2006 TR Bill Comp
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Page 27 of 47
Pacific Northern Gas (N.E.) Ltd. (Tumbler Ridge Division)
Bill Comparison January 2006 to April 2006
NSP Rates Annual Bill Proposed Rates Annual Bill Annual Bill Customer Classification Jan. 1, 2006 Estimate Apr. 1, 2006 Estimate Difference Annual Use $ / GJ $ $ / GJ $ $ % Residential: 74.6 GJ Monthly Fixed Charge @ 8.50 / mo. 1.367 102.00 1.367 102.00 0.00 Delivery Charge 5.930 442.38 5.930 442.38 0.00 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.531 39.61 0.531 39.61 (0.00) Interim Rate Refund Rider 0.000 0.00 0.000 0.00 0.00 583.99 583.99 (0.00) 0.0% Gas Supply Charge 8.822 658.12 6.822 508.92 (149.20) GCVA Rider (0.350) (26.11) (0.350) (26.11) 0.00 632.01 482.81 (149.20) -23.6% $16.300 /GJ $1,216.00 $14.300 /GJ $1,066.80 ($149.20) -12.3% Small Commercial: 553.9 GJ Monthly Fixed Charge @ 8.50 / mo. 0.184 102.00 0.184 102.00 0.00 Delivery Charge 5.116 2,833.75 5.116 2,833.75 0.00 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.531 294.12 0.531 294.12 0.00 Interim Rate Refund Rider 0.000 0.00 0.000 0.00 0.00 3,229.87 3,229.87 0.00 0.0% Gas Supply Charge 8.822 4,886.51 6.822 3,778.71 (1,107.80) GCVA Rider (0.350) (193.87) (0.350) (193.87) 0.00 4,692.64 3,584.84 (1,107.80) -23.6% $14.303 /GJ $7,922.51 $12.303 /GJ $6,814.71 ($1,107.80) -14.0% Billcomparisons-06 Effective Apr 2006 TR Bill Comp
APPENDIX ANSP 2006 Mar. 15 '06 to Order No. G-100-06 Tab Rates Page 28 of 47 Tumbler Ridge 2006 Rate App.
Page 9
Pacific Northern Gas (N.E.) Ltd. (Tumbler Ridge Division)
Determination of 2006 Revenue Stabilization Adjustment Mechanism (RSAM) Rider
Residential Actual RSAM Balance 12/31/04 $121,531 Recovery of RSAM in 2005 to 12/31/05 ($20,308) RSAM Deferral in 2005 to 12/31/05 Actual RSAM Balance 12/31/05 $147,904 Years of Amortization RSAM Balance divided by Years of Amortization equals 2006 Amortization Forecast 2006 Deliveries (GJ) One Year of Amortization divided by 2006 Deliveries equals RSAM Rate Rider ($/GJ)
Small Commercial Total $26,593 $148,123 ($7,271) ($27,580) $46,681 $16,269 $62,950 $35,590 $183,494 3 3 3 $49,301 $11,863 $61,165 79,247 36,004 115,250 0.622 0.330 0.531
NSP 2006 Mar. 15 '06 APPENDIX A Tab 1 to Order No. G-100-06 Tumbler Ridge Page 29 of 47 2006 Rate App. Page 1 Pacific Northern Gas (N.E.) Ltd. (Tumbler Ridge Division)
UTILITY INCOME & RETURN SCHEDULE 1 (000's)
Line NSP Mar. 9 06 Actual No. 2006 Update 2005 Source 1 Energy sales (TJ) 136 136 126 Tab Rates, page 5 2 Average rate per GJ $15.15 $16.04 $13.61 3 4 Transportation service (TJ) 534 500 563 Tab Rates, page 5 5 Average rate per GJ $0.53 $0.54 $0.58 6 7 Total deliveries (TJ) 670 636 689 Tab Rates, page 5 8 9 Utility revenue 10 Energy sales $2,002 $2,099 $1,719 11 Interim rates - sales 63 87 - Tab Rates, page 3 12 Transportation service 260 244 324 13 Interim rates - transportation 21 24 1 Tab Rates, page 3 14 15 2,346 2,454 2,044 16 Cost of sales 1,203 1,202 920 Tab Rates, page 4 17 18 Gross margin 1,142 1,251 1,124 19 20 Operating expenses 570 672 522 Tab 1, page 2, line 6 21 Maintenance expenses 62 62 40 Tab 1, page 2, line 10 22 Admin. & general expenses 134 135 118 Tab 1, page 2, line 16 23 Property taxes, BC capital tax 38 38 38 Tab 1, page 6, line 4 24 Depreciation 163 163 144 Tab 2, page 3, line 45 25 Amortization 17 20 13 Tab 2, page 4, line 14 26 Investment income, other revenue (8) ( 8) (8) Tab 1, page 7, line 7 27 2006 Settlement Allowance (2) 0 28 972 1,081 868 29 30 Earned return before income taxes 170 170 256 31 Income taxes 68 68 92 Tab 3, page 1, line 14 32 33 Earned return $102 $102 $164 34 35 Utility rate base $1,153 $1,151 $1,127 Tab 2, page 1, line 20 36 37 Return on rate base 8.87% 8.87% 14.52% Tab 5, page 1, line 23
NSP 2006 Mar. 15 '06 APPENDIX A Tab 2 to Order No. G-100-06 Tumbler Ridge Page 30 of 47 2006 Rate App. Page 1 Pacific Northern Gas (N.E.) Ltd. (Tumbler Ridge Division)
UTILITY RATE BASE SCHEDULE 2 (000's)
Line NSP Mar. 9 06 Actual No. 2006 Update 2005 Source 1 Plant in service beginning of year $7,749 $7,749 $7,607 Tab 2, page 2, line 46 2 Additions 173 173 142 Tab 2, page 2, line 46 3 Disposals - - - Tab 2, page 2, line 46 4 5 Plant in service end of year 7,921 7,921 7,749 6 Accumulated depreciation 5,256 5,256 5,007 Tab 2, page 3, line 45 7 8 Net plant in service end of year 2,665 2,665 2,742 9 10 Net plant beginning of year 2,742 2,742 2,853 Tab 2, pages 2 & 3, lines 46 & 39 11 12 Net plant in service midyear 2,704 2,704 2,797 13 Contributions for construction (1,257) ( 1,257) (1,338) Tab 2, page 12, line 13 14 Unamortized deferred charges 241 241 204 Tab 2, page 4, line 8 15 Deferred income taxes (415) ( 415) (415) 16 Reserve for damages (155) ( 155) (155) 17 Cash working capital 35 33 41 Tab 2, page 6, line 9 18 Other working capital - - (7) Tab 2, page 11, line 15 19 20 Utility rate base, midyear $1,153 $1,151 $1,127
NSP 2006 Mar. 15 '06 APPENDIX A Tab 3 to Order No. G-100-06 Tumbler Ridge Page 31 of 47 2006 Rate App. Page 1 Pacific Northern Gas (N.E.) Ltd. (Tumbler Ridge Division)
INCOME TAXES SCHEDULE 3 (000's)
Line NSP Mar. 9 06 Actual No. 2006 Update 2005 Source 1 Calculation of Taxable Income 2 Earned return before income taxes $170 $170 $256 Tab 1, page 1, line 30 3 Interest (63) ( 63) (62) Tab 5, page 1, lines 4, 9 & 21 4 Permanent differences - - 0 5 Timing differences 92 93 69 Tab 3, page 1, line 25 6 7 Taxable income $199 $200 $263 8 9 Calculation of Income Tax Expense 10 Income taxes payable $66 $66 $89 11 Part I.3 tax 2 2 3 12 Deferred income tax - - -13 14 Income tax expense $68 $68 $92 15 16 Particulars of Timing Differences 17 A. Tax Effects Subject To Flowthrough 18 Depreciation $163 $163 $144 Tab 1, page 1, line 24 19 Amortization 17 20 13 Tab 1, page 1, line 25 20 Capital cost allowance (79) ( 79) (82) 21 Deferred charges - - -22 Overheads capitalized (7) ( 7) (6) 23 Other (0) ( 4) (1) 24 25 Timing differences $92 $93 $69 26 27 Tax rate 33.00% 33.00% 33.75% 28 Surtax rate 1.12% 1.12% 1.12% 29 Deferred tax rate 33.00% 33.00% 33.75%
NSP 2006 Mar. 15 '06 APPENDIX A Tab 4 to Order No. G-100-06 Tumbler Ridge Page 32 of 47 2006 Rate App. Page 1 Pacific Northern Gas (N.E.) Ltd. (Tumbler Ridge Division)
COMMON EQUITY SCHEDULE 4 (000's)
Line NSP Mar. 9 06 Actual No. 2006 Update 2005 Source 1 Opening balance 2 Share capital $680 $680 $680 3 Contributed surplus - - -4 Retained earnings (444) ( 444) (540) 5 6 236 236 140 7 8 Net income $39 $39 $96 9 Shares Issued 319 318 -10 Preferred dividends - - -11 Common dividends - - -12 13 Closing balance $594 $593 $236 14 15 16 Midyear common equity $415 $415 $188 17 Investment in Non Utility - - -18 19 $415 $415 $188 20 21 Deemed utility common equity $415 $415 $406
NSP 2006 Mar. 15 '06 APPENDIX A Tab 5 to Order No. G-100-06 Tumbler Ridge Page 33 of 47 2006 Rate App. Page 1 Pacific Northern Gas (N.E.) Ltd. (Tumbler Ridge Division)
RETURN ON CAPITAL SCHEDULE 5 (000's)
Line NSP Mar. 9 06 No. 2006 Update 1 Short term borrowings $33 2 proportion 2.89% 3 rate of return 6.00% 4 return component 0.17% 5 6 Long term debt $704 7 proportion 61.11% 8 rate of return 8.67% 9 return component 5.30% 10 11 Preferred shares $0 12 proportion 0.00% 13 rate of return 0.00% 14 return component 0.00% 15 16 Common equity $415 17 proportion 36.00% 18 rate of return 9.45% 19 return component 3.40% 20 21 Total capitalization $1,153 22 23 Return on rate base 8.87% 24 25 Utility rate base $1,153
Actual 2005 Source $32 $68 2.82% 6.02% 6.00% 6.00% 0.17% 0.36% $704 $654 61.18% 57.98% 8.67% 8.89% 5.30% 5.15% $0 $0 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% $415 $406 36.00% 36.00% 9.45% 25.0% 3.40% 9.00% $1,151 $1,127 8.87% 14.52% $1,151 $1,127 Tab 2, page 1, line 20
NSP 2006 Mar. 15 '06 APPENDIX A to Order No. G-100-06 Page 34 of 47 Pacific Northern Gas (N.E.) Ltd. (Fort St. John / Dawson Creek Division)
NSP 2006 to Revised Mar. 9 '06 COST OF SERVICE COMPARISON ($000)
Revised NSP 2006 App. EXPENSES 2006 Mar. 9 '06 Difference Operating Labour 1 ,243 1,243 0 Other 1 ,976 2,027 (52) Sub-total 3 ,218 3,270 (52) Maintenance Labour 9 3 93 0 Other 1 48 148 0 Sub-total 2 41 241 0 Administrative and General Labour 0 0 0 Total Company Benefits 4 79 481 (2) Other 8 97 901 (4) Sub-total 1 ,376 1,382 (6) Total (O, M, A & G) Excluding Co. Use 4,835 4,892 (57) Transfers to Capital Operating ( 187) ( 187) 0 Transfers to Capital Admin. & Gen. ( 200) ( 201) 1 Property Taxes 8 15 815 0 Depreciation 1 ,180 1,180 0 Amortization ( 158) ( 159) 0 Other Income ( 174) ( 174) 0 2006 Settlement Allowance ( 50) 0 (50) Total Expenses Excluding Co, Use 6,061 6,167 (105) Income Taxes 3 19 310 9 Return on Common Equity 9 97 997 (1) Short Term Debt 9 0 91 (1) Long Term Debt 1 ,319 1,319 0 Preferred Shares 1 1 0 Total Cost of Service Excluding Co. Use 8,787 8,885 (98) Company Use Gas 4 19 721 Total Cost of Service Including Co. Use 9,206 9,606 2005 to 2006 Cost of Service Increase 74 172 (98) 2005 to 2006 Margin Decrease (Increase) (118) (118) 0 2006 Revenue (Sufficiency) Deficiency (44) 54 (98)
NSP 2006 Mar. 15'06 Tab Application APPENDIX A FSJ/DC to Order No. G-100-06 2006 Rate App. Page 3 Page 35 of 47 Pacific Northern Gas (N.E.) Ltd.
(Fort St. John / Dawson Creek Division)
NSP 2006 vs.Decision 2005 COST OF SERVICE COMPARISON ($000)
NSP EXPENSES 2006 Operating Labour 1 ,243 Other 1 ,976 Sub-total 3 ,218 Maintenance Labour 9 3 Other 1 48 Sub-total 2 41 Administrative and General Labour 0 Total Company Benefits 4 79 Other 8 97 Sub-total 1 ,376 Total (O, M, A & G) Excluding Co. Use 4,835 Transfers to Capital Operating ( 187) Transfers to Capital Admin. & Gen. ( 200) Property Taxes 8 15 Depreciation 1 ,180 Amortization ( 158) Other Income ( 174) 2006 Settlement Allowance ( 50) Total Expenses Excluding Co, Use 6,061 Income Taxes 3 19 Return on Common Equity 9 97 Short Term Debt 9 0 Long Term Debt 1 ,319 Preferred Shares 1 Total Cost of Service Excluding Co. Use 8,787 Company Use Gas 4 19 Total Cost of Service Including Co. Use 9,206 2005 to 2006 Cost of Service Increase 2005 to 2006 Margin Decrease (Increase) 2006 Revenue Deficiency (Sufficiency)
Decision Difference 2005 Total Subtotal 1,149 94 1,774 201 2,923 295 89 4 177 (29) 266 (26) 0 0 431 48 726 171 1,157 219 4,347 488 488 (201) 14 (173) (27) 832 (17) 1,131 50 4 (162) (153) (21) 0 (50) (212) 5,785 276 276 452 (134) 1,041 (44) 244 (154) 1,190 130 1 (0) (202) 8,713 74 74 247 8,960 74 (118) (44)
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Tab Rates FSJ/DC Page 36 of 47 2006 Rate App. Page 5
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
Bill Comparison December 2005 to January 2006
FORT ST. JOHN AREA Permanent Rates Annual Bill NSP Rates Annual Bill Annual Bill Customer Classification Dec. 31, 2005 Estimate Jan. 1, 2006 Estimate Difference Annual Use $ / GJ $ $ / GJ $ $ % Residential: 128.7 GJ Monthly Fixed Charge @ 7.00 / mo. 0.653 84.00 0.653 84.00 0.00 Delivery Charge 2.230 286.94 2.266 291.57 4.63 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.022 2.83 0.114 14.67 11.84 Interim Rate Refund Rider (0.121) (15.57) 0.000 0.00 15.57 358.20 390.24 32.04 8.9% Gas Supply Charge 9.110 1,172.22 9.600 1,235.27 63.05 GCVA Rider 0.099 12.74 0.434 55.84 43.10 1,184.96 1,291.11 106.15 9.0% $11.993 /GJ $1,543.16 $13.067 /GJ $1,681.35 $138.19 9.0% Small Commercial: 572.1 GJ Monthly Fixed Charge @ 7.00 / mo. 0.147 84.00 0.147 84.00 0.00 Delivery Charge 1.994 1,140.77 2.035 1,164.22 23.45 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.022 12.59 0.114 65.22 52.63 Interim Rate Refund Rider (0.069) (39.47) 0.000 0.00 39.47 1,197.88 1,313.44 115.56 9.6% Gas Supply Charge 9.132 5,224.42 9.596 5,489.87 265.45 GCVA Rider 0.099 56.64 0.434 248.29 191.65 5,281.06 5,738.16 457.10 8.7% $11.325 /GJ $6,478.93 $12.326 /GJ $7,051.60 $572.67 8.8% Billcomparisons-06 Effective Jan 2006 FSJ Bill Comp
APPENDIX A NSP 2006 Mar. 15 '06 Tab Rates to Order No. G-100-06 FSJ/DC Page 37 of 47 2006 Rate App. Page 6 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
Bill Comparison December 2005 to January 2006
DAWSON CREEK AREA Permanent Rates Annual Bill Customer Classification Dec. 31, 2005 Estimate Annual Use $ / GJ Residential: 120.6 GJ Monthly Fixed Charge @ 7.00 / mo. 0.696 84.00 Delivery Charge 2.032 245.08 GCVA Co. Use Rider 0.000 0.00 RSAM Rider 0.022 2.65 Interim Rate Refund Rider (0.121) (14.59) 317.14 Gas Supply Charge 9.110 1,098.74 GCVA Rider 0.099 11.94 1,110.68 $11.838 /GJ $1,427.82 Small Commercial: 656.7 GJ Monthly Fixed Charge @ 7.00 / mo. 0.128 84.00 Delivery Charge 1.457 956.81 GCVA Co. Use Rider 0.000 0.00 RSAM Rider 0.022 14.45 Interim Rate Refund Rider (0.069) (45.31) 1,009.95 Gas Supply Charge 9.132 5,996.98 GCVA Rider 0.099 65.01 6,062.00 $10.769 /GJ $7,071.94 Billcomparisons-06 Effective Jan 2006 DC Bill Comp
NSP Rates Annual Bill Annual Bill Jan. 1, 2006 Estimate Difference $ $ / GJ $ $ % 0.696 84.00 0.00 2.068 249.42 4.34 0.000 0.00 0.00 0.114 13.75 11.10 0.000 0.00 14.59 347.17 30.03 9.5% 9.600 1,157.84 59.10 0.434 52.34 40.40 1,210.18 99.50 9.0% $12.912 /GJ $1,557.35 $129.53 9.1% 0.128 84.00 0.00 1.498 983.74 26.92 0.000 0.00 0.00 0.114 74.86 60.42 0.000 0.00 45.31 1,142.60 132.65 13.1% 9.596 6,301.69 304.71 0.434 285.01 219.99 6,586.70 524.70 8.7% $11.770 /GJ $7,729.30 $657.36 9.3%
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Page 38 of 47
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
Bill Comparison December 2005 to January 2006
Permanent Rates Annual Bill NSP Rates Annual Bill Annual Bill Customer Classification Dec. 31, 2005 Estimate Jan. 1, 2006 Estimate Difference Annual Use $ / GJ $ $ / GJ $ $ % Residential: 124.6 GJ Monthly Fixed Charge @ 7.00 / mo. 0.674 84.00 0.674 84.00 0.00 Delivery Charge 2.131 265.61 2.167 270.10 4.49 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.022 2.74 0.114 14.21 11.47 Interim Rate Refund Rider (0.121) (15.08) 0.000 0.00 15.08 337.27 368.31 31.04 9.2% Gas Supply Charge 9.110 1,135.48 9.600 1,196.55 61.07 GCVA Rider 0.099 12.34 0.434 54.09 41.75 1,147.82 1,250.64 102.82 9.0% $11.915 /GJ $1,485.09 $12.989 /GJ $1,618.95 $133.86 9.0% Small Commercial: 614.4 GJ Monthly Fixed Charge @ 7.00 / mo. 0.137 84.00 0.137 84.00 0.00 Delivery Charge 1.726 1,060.15 1.767 1,085.34 25.19 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.022 13.52 0.114 70.04 56.52 Interim Rate Refund Rider (0.069) (42.39) 0.000 0.00 42.39 1,115.27 1,239.38 124.11 11.1% Gas Supply Charge 9.132 5,610.70 9.596 5,895.78 285.08 GCVA Rider 0.099 60.83 0.434 266.65 205.82 5,671.53 6,162.43 490.90 8.7% $11.046 /GJ $6,786.80 $12.047 /GJ $7,401.81 $615.01 9.1% Note: This bill comparison is the average of the uses per account and rates that apply to each of the Fort St. John and Dawson Creek delivery areas.
Billcomparisons-06 Effective Jan 2006 FSJDC Bill Comp
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Page 39 of 47
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
Bill Comparison January 2006 to April 2006
FORT ST. JOHN AREA
NSP Rates Annual Bill Proposed Rates Annual Bill Annual Bill Customer Classification Jan. 1, 2006 Estimate Apr. 1, 2006 Estimate Difference Annual Use $ / GJ $ $ / GJ $ $ % Residential: 128.7 GJ Monthly Fixed Charge @ 7.00 / mo. 0.653 84.00 0.653 84.00 0.00 Delivery Charge 2.266 291.57 2.266 291.57 0.00 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.114 14.67 0.114 14.67 0.00 Interim Rate Refund Rider 0.000 0.00 0.000 0.00 0.00 390.24 390.24 0.00 0.0% Gas Supply Charge 9.600 1,235.27 8.384 1,078.80 (156.47) GCVA Rider 0.434 55.84 0.000 0.00 (55.84) 1,291.11 1,078.80 (212.31) -16.4% $13.067 /GJ $1,681.36 $11.417 /GJ $1,469.04 ($212.31) -12.6% Small Commercial: 572.1 GJ Monthly Fixed Charge @ 7.00 / mo. 0.147 84.00 0.147 84.00 0.00 Delivery Charge 2.035 1,164.22 2.035 1,164.22 0.00 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.114 65.22 0.114 65.22 0.00 Interim Rate Refund Rider 0.000 0.00 0.000 0.00 0.00 1,313.44 1,313.44 (0.00) 0.0% Gas Supply Charge 9.596 5,489.87 8.380 4,794.20 (695.67) GCVA Rider 0.434 248.29 0.000 0.00 (248.29) 5,738.16 4,794.20 (943.96) -16.5% $12.326 /GJ $7,051.61 $10.676 /GJ $6,107.64 ($943.97) -13.4% Billcomparisons-06 Effective Apr 2006 FSJ Bill Comp
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Page 40 of 47
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
Bill Comparison January 2006 to April 2006
DAWSON CREEK AREA
NSP Rates Annual Bill Customer Classification Jan. 1, 2006 Estimate Annual Use $ / GJ Residential: 120.6 GJ Monthly Fixed Charge @ 7.00 / mo. 0.696 84.00 Delivery Charge 2.068 249.42 GCVA Co. Use Rider 0.000 0.00 RSAM Rider 0.114 13.75 Interim Rate Refund Rider 0.000 0.00 347.17 Gas Supply Charge 9.600 1,157.84 GCVA Rider 0.434 52.34 1,210.18 $12.912 /GJ $1,557.35 Small Commercial: 656.7 GJ Monthly Fixed Charge @ 7.00 / mo. 0.128 84.00 Delivery Charge 1.498 983.74 GCVA Co. Use Rider 0.000 0.00 RSAM Rider 0.114 74.86 Interim Rate Refund Rider 0.000 0.00 1,142.60 Gas Supply Charge 9.596 6,301.69 GCVA Rider 0.434 285.01 6,586.70 $11.770 /GJ $7,729.30 Billcomparisons-06 Effective Apr 2006 DC Bill Comp
Proposed Rates Annual Bill Annual Bill Apr. 1, 2006 Estimate Difference $ $ / GJ $ $ % 0.696 84.00 0.00 2.068 249.42 0.00 0.000 0.00 0.00 0.114 13.75 0.00 0.000 0.00 0.00 347.17 0.00 0.0% 8.384 1,011.18 (146.66) 0.000 0.00 (52.34) 1,011.18 (199.00) -16.4% $11.262 /GJ $1,358.35 ($199.00) -12.8% 0.128 84.00 0.00 1.498 983.74 0.00 0.000 0.00 0.00 0.114 74.86 0.00 0.000 0.00 0.00 1,142.60 0.00 0.0% 8.380 5,503.15 (798.55) 0.000 0.00 (285.01) 5,503.15 (1,083.56) -16.5% $10.120 /GJ $6,645.75 ($1,083.56) -14.0%
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Page 41 of 47
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
Bill Comparison January 2006 to April 2006
NSP Rates Annual Bill Proposed Rates Annual Bill Annual Bill Customer Classification Jan. 1, 2006 Estimate Apr. 1, 2006 Estimate Difference Annual Use $ / GJ $ $ / GJ $ $ % Residential: 124.6 GJ Monthly Fixed Charge @ 7.00 / mo. 0.674 84.00 0.674 84.00 0.00 Delivery Charge 2.167 270.10 2.167 270.10 0.00 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.114 14.21 0.114 14.21 0.00 Interim Rate Refund Rider 0.000 0.00 0.000 0.00 0.00 368.31 368.31 0.00 0.0% Gas Supply Charge 9.600 1,196.55 8.384 1,044.99 (151.56) GCVA Rider 0.434 54.09 0.000 0.00 (54.09) 1,250.65 1,044.99 (205.66) -16.4% $12.989 /GJ $1,618.95 $11.339 /GJ $1,413.30 ($205.66) -12.7% Small Commercial: 614.4 GJ Monthly Fixed Charge @ 7.00 / mo. 0.137 84.00 0.137 84.00 0.00 Delivery Charge 1.767 1,085.34 1.767 1,085.34 0.00 GCVA Co. Use Rider 0.000 0.00 0.000 0.00 0.00 RSAM Rider 0.114 70.04 0.114 70.04 0.00 Interim Rate Refund Rider 0.000 0.00 0.000 0.00 0.00 1,239.38 1,239.38 0.00 0.0% Gas Supply Charge 9.596 5,895.78 8.380 5,148.67 (747.11) GCVA Rider 0.434 266.65 0.000 0.00 (266.65) 6,162.43 5,148.67 (1013.76) -16.5% $12.047 /GJ $7,401.81 $10.397 /GJ $6,388.05 ($1,013.76) -13.7% Note: This bill comparison is the average of the uses per account and rates that apply to each of the Fort St. John and Dawson Creek delivery areas.
Billcomparisons-06 Effective Apr 2006 FSJDC Bill Comp
APPENDIX ANSP 2006 Mar. 15 '06 to Order No. G-100-06 Tab Rates Page 42 of 47 FSJ/DC 2006 Rate App.
Page 15
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
Determination of 2006 Revenue Stabilization Adjustment Mechanism (RSAM) Rider
Residential Actual RSAM Balance 12/31/04 $193,463 Recovery of RSAM in 2005 to 12/31/05 ($33,546) RSAM Deferral in 2005 to 12/31/05 $427,114 Actual RSAM Balance 12/31/05 $587,032 Years of Amortization RSAM Balance divided by Years of Amortization equals 2006 Amortization $195,677 Forecast 2006 Deliveries (GJ) 1,724,179 One Year of Amortization divided by 2006 Deliveries equals RSAM Rate Rider ($/GJ)
Small Commercial Total $248,684 $442,148 ($24,873) ($58,419) $217,946 $645,061 $441,757 $1,028,789 3 3 3 $147,252 $342,930 1,297,042 3,021,220 0.113 0.114 0.114
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Tab 1 Page 43 of 47 FSJ/DC 2006 Rate App. Page 1
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
UTILITY INCOME & RETURN SCHEDULE 1 (000's)
Line NSP No. 2006 1 Energy sales (TJ) 3,722 2 Average rate per GJ $11.81 3 4 Transportation service (TJ) 1,073 5 Average rate per GJ $0.81 6 7 Total deliveries (TJ) 4,795 8 9 Utility revenue 10 Energy sales $44,017 11 Interim rates - sales (40) 12 Transportation service 872 13 Interim rates - transportation (4) 14 15 44,846 16 Cost of sales 35,640 17 18 Gross margin 9,206 19 20 Operating expenses 3,450 21 Maintenance expenses 241 22 Admin. & general expenses 1,176 23 Property taxes, BC capital tax 815 24 Depreciation 1,180 25 Amortization (158) 26 Investment income, other revenue (174) 27 2006 Settlement Allowance (50) 28 29 6,480 30 31 Earned return before income taxes 2,726 32 Income taxes 319 33 34 Earned return $2,407 35 36 Utility rate base $30,095 37 38 Return on rate base 8.00%
Mar. 9 '06 Actual Update 2005 Source 3,722 3 176 Tab Rates, page 7 $11.84 $10.18 1,073 1 274 Tab Rates, page 7 $0.88 $0.74 4,795 4 450 Tab Rates, page 7 $44,006 $32,334 49 - Tab Rates, page 7 940 937 5 - Tab Rates, page 7 45,000 33,272 35,393 24,482 Tab Rates, page 8 9,606 8,789 3,803 3,205 Tab 1, page 2, line 6 241 364 Tab 1, page 2, line 10 1,181 960 Tab 1, page 2, line 16 815 832 Tab 1, page 6, line 4 1,180 1,130 Tab 2, page 3, line 49 (159) 29 Tab 2, page 4, line 19 (174) (190) Tab 1, page 7, line 7 - 6,887 6,329 2,719 2,460 310 287 Tab 3, page 1, line 14 $2,409 $2,173 $30,119 $30,546 Tab 2, page 1, line 21 8.00% 7.11% Tab 5, page 1, line 23
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Tab 2 Page 44 of 47 FSJ/DC 2006 Rate App. Page 1
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
UTILITY RATE BASE SCHEDULE 2 (000's)
Line NSP No. 2006 1 Plant in service beginning of year $57,481 2 Additions 2,284 3 Disposals (121) 4 5 Plant in service end of year 59,644 6 Accumulated depreciation 22,513 7 8 Net plant in service end of year 37,130 9 10 Net plant beginning of year 36,360 11 12 Net plant in service midyear 36,745 14 Contributions for construction (7,123) 15 Unamortized deferred charges 630 16 Deferred income taxes (553) 17 Reserve for damages (69) 18 Cash working capital 2 52 2 77 19 Other working capital 213 20 21 Utility rate base, midyear $30,095
Mar. 9 '06 Actual Update 2005 Source $57,481 $55,528 Tab 2, page 3, line 46 2,285 2,143 Tab 2, page 3, line 46 (121) ( 191) Tab 2, page 3, line 46 59,645 57,481 22,514 21,121 Tab 2, page 5, line 43 37,131 36,360 36,360 35,663 Tab 2, pages 3 & 5, lines 46 & 43 36,746 36,012 (7,123) (7,246) Tab 2, page 14, line 13 627 620 Tab 2, page 7, line 12 (553) (553) (69) ( 69) 1,657 Tab 2, page 8, line 10 213 125 Tab 2, page 13, line 15 $30,119 $30,546
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Tab 3 Page 45 of 47 FSJ/DC 2006 Rate App. Page 1
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
INCOME TAXES SCHEDULE 3 (000's)
Line NSP No. 2006 1 Calculation of Taxable Income 2 Earned return before income taxes $2,726 3 Interest (1,410) 4 Permanent differences 8 5 Timing differences (496) 6 7 Taxable income $829 8 9 Calculation of Income Tax Expense 10 Income taxes payable $273 11 Part I.3 tax 45 12 Deferred income tax 0 13 14 Income tax expense $319 15 16 Particulars of Timing Differences 17 A. Tax Effects Subject To Flowthrough 18 Depreciation $1,180 19 Amortization (158) 20 Capital cost allowance (1,211) 21 Deferred charges 0 22 Overheads capitalized (310) 23 Other 3 24 25 26 Timing differences ($496) 27 28 Tax rate 33.00% 29 Surtax Rate 1.12% 30 Deferred tax rate 33.00%
Mar. 9 '06 Actual Update 2005 Source $2,719 $2,460 Tab 1, page 1, line 30 (1,411) (1,408) Tab 5, page 1, lines 4, 9 & 21 8 8 (514) (410) Tab 3, page 1, line 26 $802 $650 $265 $219 45 68 0 - $310 $287 $1,180 $1,130 Tab 1, page 1, line 24 (159) 29 Tab 1, page 1, line 25 (1,211) (1,249) 0 0 (311) (271) (14) ( 49) ($514) ($410) 33.00% 33.75% 1.12% 1.12% 33.00% 33.75%
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Tab 4 Page 46 of 47 FSJ/DC 2006 Rate App. Page 1
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
COMMON EQUITY SCHEDULE 4 (000's)
Line NSP No. 2006 1 Opening balance 2 Share capital $7,845 3 Contributed surplus 0 4 Retained earnings 3,876 5 6 11,721 7 8 Net income 921 9 Shares issued 0 10 Preferred dividends (2) 11 Common dividends (2,697) 12 13 Closing balance $9,944 14 15 16 Midyear common equity $10,833
Mar. 9 '06 Actual Update 2005 Source $7,845 $7,845 0 - 3,876 3,130 11,721 10,975 948 765 0 - (2) - (2,704) - $9,964 $11,740 $10,843 $11,358
APPENDIX A NSP 2006 Mar. 15 '06 to Order No. G-100-06 Tab 5 Page 47 of 47 FSJ/DC 2006 Rate App. Page 1
Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division)
RETURN ON CAPITAL SCHEDULE 5 (000's)
Line NSP No. 2006 1 Short term borrowings $1,506 2 proportion 5.00% 3 rate of return 6.00% 4 return component 0.30% 5 6 Long term debt $17,739 7 proportion 58.94% 8 rate of return 7.44% 9 return component 4.38% 10 11 Preferred shares $16 12 proportion 0.05% 13 rate of return 6.48% 14 return component 0.00% 15 16 Common equity $10,834 17 proportion 36.00% 18 rate of return 9.20% 19 return component 3.31% 20 21 Total capitalization $30,095 22 23 Return on rate base 8.00% 24 25 Utility rate base $30,095
Mar. 9 '06 Actual Update 2005 Source $1,522 $3,631 5.05% 11.89% 6.00% 6.00% 0.30% 0.71% $17,739 $15,537 58.90% 50.87% 7.44% 7.66% 4.38% 3.90% $16 $20 0.05% 0.07% 6.48% 6.48% 0.00% 0.00% $10,842 $11,358 36.00% 37.18% 9.20% 6.73% 3.31% 2.50% $30,119 $30,546 8.00% 7.11% $30,119 $30,546 Tab 2, page 1, line 21