PACIFIC NORTHERN GAS (N.E.) LTD. (Fort St. John/Dawson Creek Division) 2005 Revenue Requirements Application to the B.C. Utilities Commission

Transcription

1 PACIFIC NORTHERN GAS (N.E.) LTD. (Fort St. John/Dawson Creek Division) 2005 Revenue Requirements Application to the B.C. Utilities Commission December 17, 2004

2 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division) 2005 REVENUE REQUIREMENTS APPLICATION December 17, 2004 INDEX Description Tab Index...Index Application Narrative.Application Proposed Rate Changes...Rates Regulatory Schedules Utility Income and Return (Schedule 1)...1 Utility Rate Base (Schedule 2)...2 Income Taxes (Schedule 3)...3 Common Equity (Schedule 4)...4 Return on Capital (Schedule 5)...5

3 Tab Application Page 1 IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, c. 473, as amended - and - In The Matter Of PACIFIC NORTHERN GAS (N.E.) LTD. (Fort St. John/Dawson Creek Division) 2005 REVENUE REQUIREMENTS APPLICATION December 17, 2004 TO: British Columbia Utilities Commission Sixth Floor 900 Howe Street, P.O. Box 250 Vancouver, B.C. V6Z 2N3 PACIFIC NORTHERN GAS (N.E.) LTD. ( PNG(N.E.) ) hereby applies to the British Columbia Utilities Commission (the "Commission") for approval to amend the rate schedules of PNG(N.E.) s Fort St. John/Dawson Creek ( ) Division in accordance with this Application, effective January 1, PNG(N.E.) seeks such approval on an interim basis pursuant to section 89 of the Utilities Commission Act (the "Act") and on a permanent basis pursuant to section 58 of the Act. In support of this Application, PNG(N.E.) submits the following:

4 Tab Application Page 2 This Application sets forth PNG(N.E.) s projected revenues and forecast test year cost of service for 2005 for its Fort St. John/Dawson Creek division. The shortfall between revenues and cost of service in 2005 is $239,000. The following page compares the 2004 cost of service approved by the Commission in its July 29, 2004 Decision on PNG(N.E.) s 2004 revenue requirement application ( Decision 2004 ) to the 2005 cost of service described in this Application. This Application does not attempt to compare PNG(N.E.) s actual 2004 costs to the 2005 test year forecast. PNG(N.E.) s 2004 actual costs will be available in early February PNG(N.E.) prepares its annual budget using zero based budgeting principles. PNG(N.E.) critically evaluates its proposed expenditures with the overall objective of providing customers with safe, secure and reliable natural gas delivery service at just and reasonable rates.

5 Pacific Northern Gas (N.E.) Ltd. (Fort St. John / Dawson Creek Division) Tab Application Page 3 Test Year 2005 vs. Decision 2004 COST OF SERVICE COMPARISON ($000) Test Year Decision Difference EXPENSES Total Subtotal Operating Labour 1,149 1, Other 1,868 1, Sub-total 3,017 2, Maintenance Labour (3) Other Sub-total Administrative and General Labour Total Company Benefits (11) Other Sub-total 1,136 1, Total (O, M, A & G) Excluding Co. Use 4,419 3, Transfers to Capital Operating (209) (203) (6) Transfers to Capital Admin. & Gen. (166) (175) 9 Property Taxes Depreciation 1,069 1,237 (168) Amortization 3 21 (18) Other Income (153) (153) (0) (113) Total Expenses Excluding Co, Use 5,795 5, Income Taxes (85) Return on Common Equity 1,093 1, Short Term Debt Long Term Debt 1,190 1,395 (205) Preferred Shares 1 2 (1) (83) Total Cost of Service Excluding Co. Use 8,866 8, Company Use Gas Total Cost of Service Including Co. Use 9,107 8, to 2005 Cost of Service Increase/(Decrease) to 2005 Margin Decrease Revenue Deficiency 239

6 Tab Application Page 4 The major components of the 2005 cost of service are summarized below and compared to Decision The Table shows the main drivers of the projected revenue deficiency in Higher operating, maintenance, administrative and general expenses in 2005 together with lower forecast gas deliveries in 2005 result in the revenue deficiency shown at the bottom of the Table. $000 s Cost of Service Item Test Year 2005 Decision /2004 Difference Operating, Maintenance, Administrative and General Expenses Transfers to Capital, Operating, Administrative and General Other Cost of Service Items including property taxes and depreciation Return components including return on equity, income taxes and debt costs $4,419 $3,993 $427 (374) (378) 4 1,751 1,866 (115) 3,071 3,154 (83) Cost of Service Ex. Co. Use Gas Cost $8,866 $8,637 $229 Margin Reduction from 2004 to 2005 $8,627 $8,637 $10 Total 2005 Revenue Deficiency $239 The following explains in detail the various components of PNG(N.E.) s 2005 cost of service as summarized above.

7 Tab Application Page 5 OPERATING COSTS Cost Element 665 Pipelines 673 Removing & Resetting meters 675 Other General Operations 688 Other General Operations 711/713/714 Customer Care 718 Uncollectible Accounts Add Shared Service Costs Other Operating Costs net of co. use gas cost Test Year 2005 Decision 2004 $000 s 2005/04 Change Actual 2003 Actual 2002 Actual 2001 Actual 2000 $88 $102 ($14) $41 $73 $256 $33 $205 $200 $5 $242 $194 $113 $68 $247 $186 $61 $229 $185 $147 $188 $381 $362 $19 $367 $339 $319 $501 $365 $289 $76 $300 $304 $286 $508 $125 $47 $74 $178 $49 $40 $182 $805 $674 $131 $682 $692 $511 $429 $801 $795 $6 $846 $753 $657 $822 Subtotal $3,017 $2,655 $362 $2,885 $2,589 $2,329 $2,731 Transfers to Capital Total Operating Expenses net of co. use gas cost ($209) ($203) ($6) ($246) ($188) ($205) ($194) $2,808 $2,452 $356 $2,639 $2,401 $2,124 $2,537

8 Tab Application Page 6 The above figures exclude the Company use gas operating cost as that is treated as a pass through cost since it is dependant on prevailing gas supply market prices. The 2004 to 2005 increase in the mains and services account 675 reflects an increase in the cost of leak survey for distribution mains and services in This is simply a result of all the lines being leak surveyed on a 5 year rotation, and the 2005 level of activity being greater than that budgeted for The major cost component in the Other General Operations account 688 is a forecast of the amount of allowable time off with pay. The increase for 2005 reflects the increases in vacation time entitlement due to tenure with the Company and inflation for The increase in Customer Care (711/713/714) costs shown in the above table results from adjusting the estimate of the share of outside billing services costs payable by PNG(N.E.) to PNG to reimburse PNG for the costs paid on behalf of PNG(N.E.) to the outside billing service providers for expenses in account 713. These costs are allocated directly to PNG(N.E.), on an invoice by invoice basis, based on the percentage of core market customers in this division versus total customers. The allocation percentage has increased from 38.5 percent in 2004 to 39.5 percent in 2005, as the region now accounts for a higher percentage of total customers. The costs allocated are direct third party service provider costs, including costs for printing and mailing customer bills, processing customer payments, as well as software licence fees, and therefore are not included in the pool of costs allocated by PNG to PNG(N.E.) under the shared service cost arrangements. A summary of the costs together with an estimate of the annual per customer costs is provided on the following page. The summary refers to one area called Database management and improvements. It is noted that a large portion of the database improvement charges for 2005 relate to improving the ability to manage bad debt and delinquency processes, which should help to reduce future bad debt write offs and reduce costs.

9 Tab Application Page 7 Costs per customer Percentage Change Bill printing, including stationery and printing costs $ 3.03 $ 2.44 plus on-line web access for customers (in 2005) Postage 7.8 bills per customer $ bills per customer $ 4.13 Postal Code data monthly updates (Canada Post) $ 0.06 N/A Automatic Remittance processing (telephone, internet) $ 0.83 $ 0.77 Pre-Authorized Bill payment processing (drafts) $ 0.10 $ 0.11 Customer Information System (software usage fee, per contract) $ 9.19 $ 8.78 Database management and improvements: Database refresh & clean up charges $ 0.67 $ 0.60 New scripts and program changes $ 0.79 $ 0.65 Bad debt software upgrade $ 1.58 $ - Other program upgrades $ 0.50 Rate code restructuring $ 0.90 Split of commodity and delivery charges on bills $ 0.65 $ 3.04 $ 3.29 Total costs directly allocated by PNG - West $ $ % Number of customers (DC/FSJ) 15,280 15, % % of Total customers 39.52% 38.50% 2.6% Total costs directly allocated by PNG West ($000's) Locally incurred costs, including data lines, labour, and gas testing and sampling costs ($000's) Sub-total: As applied for % Less amounts disallowed in 2004 ($000's) - (52) Test Year 2005 / Decision %

10 Tab Application Page 8 Uncollectible accounts (account 718) has increased from $47,000 in Decision 2004 to $125,000 in 2005 based on actual bad debt write off experience over the past several years which has averaged 0.5 percent of revenues for all Divisions of PNG. MAINTENANCE COSTS The forecast expenditure levels for 2005 are consistent with Decision They are at an appropriate level to ensure safe, reliable, and economical service to all customers. An increase in expenditures for right-of-way slashing ($16,000) is reflected in account 865 pipelines. This will ensure the high pressure lines serving the Dawson Creek area are adequately cleared prior to the leak survey being performed. This accounts for the majority of the 2004 to 2005 maintenance cost increase. ADMINISTRATIVE AND GENERAL COSTS The following provides an historical summary of administrative and general costs. Cost Element Test Year 2005 Decision 2004 $000 s 2005/2004 Difference Actual 2003 Actual 2002 Actual 2001 Actual Administration $499 $507 ($8) $308 $319 $315 $ Special Services $22 $17 $5 $49 $2 $8 $ Insurance $180 $123 $57 $84 $75 $67 $ Employee Ben. $386 $397 ($11) $277 $248 $339 $ General $49 $48 $1 $37 $38 $35 $35 Sub-total $1,136 $1,092 $61 $755 $682 $764 $1,010 Less: Transfers to Capital ($166) ($175) $9 ($131) ($186) ($148) ($136) Total $970 $917 $53 $624 $496 $616 $874

11 Tab Application Page 9 Administrative and general costs net of transfers to capital have increased from $874,000 in 2000 to $970,000 in 2005, an increase of $96,000 or 11.0 percent over the six-year period. The increase in total administrative and general expenses of $53,000 from 2004 to 2005 reflects primarily higher insurance costs offset by reductions in shared service costs and employee benefit costs. The budget for insurance expense in 2005 has increased significantly above 2004 levels. This estimate is based on insurance quotes obtained in November 2004, for insurance coverage for PNG (consolidated). The basis of allocation of insurance premiums by PNG to PNG(N.E) has changed in Prior to 2005, property and commercial liability insurance were allocated on the basis of a fixed percentage, and there was no allocation of Director s and Officer s insurance. Beginning in 2005, property insurance premiums are allocated on the basis of replacement value, adjusted for estimated risk of claims, commercial liability premiums are allocated on the basis of customer count, Directors and Officers premiums are allocated on the basis of net income and fiduciary insurance premiums are allocated based on employee count. This resulted in a significant increase in commercial liability insurance premiums for, as well as the addition of Directors and Officers and fiduciary premiums, partially offset by a reduction in property insurance premiums. As in 2004, PNG(N.E.) is unable to obtain any insurance coverage for Terrorists Acts. PNG(N.E.) is therefore requesting continued Commission approval of a deferral account to record costs that would be incurred should PNG(N.E.) suffer any damage due to a terrorist act.

12 Tab Application Page 10 SHARED SERVICE CHARGES BY PNG TO PNG(N.E.) The following Table summarizes the shared service charges by PNG, the parent company of PNG(N.E.), to enable parties to understand exactly where PNG(N.E.) records the shared service charges by Commission account number. Costs Allocated to PNG(N.E.) FSJ / DC 721 Administration 32.3% 685 General Operations 32.3% 711/713/714 Customer Care 32.3% Test Year 2005 $ Decision 2004 $ $000 s 2005/04 Change ($33) Actual 2003 $ Actual 2002 $ Actual 2001 $ Actual 2000 $ Total Allocation 1, Total Benefits Total $1,290 $1,174 $116 $985 $1,003 $856 $874 Shared service charges billed by PNG have increased by 9.9 percent from 2004 levels, or $116,000. The benefits surcharge on labour billed to PNG(N.E.) was increased from 31 percent to 32.3 percent, reflecting the budgeted benefits expenses for In addition, the allocation of certain costs on the basis of customer count increased from 38.5 percent to 39.5 percent, due to the increase in the number of customers in the area versus the total number of all PNG customers.

13 Tab Application Page 11 There are six categories of costs that are pooled and allocated by PNG to PNG(N.E.) based on time spent, customer count, or employee count. A 32.3 percent fringe benefit surcharge is attached to any labour included in the cost pools. A description of the various services rendered and the method of allocation are provided in the Table below: Account Code Description of Services (Cost Pool) 721 All Vancouver 721 expenses, including Executives, IT, Accounting, HR, Finance & Regulatory 685 Vancouver Engineering services Method of Allocation % of Costs Allocated to PNG(N.E.) Fixed percentage, based on historical time study 19.5% Fixed percentage, based on historical time study 19.5% 685 Terrace management (3 employees) Customer Count 39.5% 685 Terrace accounting, including payroll and accounts payables processing, and plant accounting; Warehouse technical services Employee Count 20.8% 685 Drafting technical services Customer Count 39.5% 713 Customer Care Centre Customer Count 39.5%

14 Tab Application Page 12 TRANSFERS TO CAPITAL $000 s Cost Element Test Year 2005 Decision 2004 Forecast 2004 Actual 2003 Actual 2002 Actual 2001 Actual 2000 Operating $209 $203 $228 $246 $188 $205 $194 Administration $166 $175 $183 $131 $186 $148 $136 % of Overhead Allocated 18.78% 19.9% 19.9% 22% 23% 25% 17% The allocation of overhead to capital projects for 2005 has been calculated using a rate of percent, compared to 19.9 percent in This was derived from the projected budgeted 2005 transfer rates, based upon the budgeted component of direct labour in capital projects expected to be completed during the year. In 2005, PNG is requesting Commission approval to fix the transfer rate for 2005 at percent of actual overhead expenses. In other words, the percent figure will be used to calculate transfers to capital regardless of the actual component of direct labour in capital projects completed during PROPERTY TAXES Test Year 2005 Decision /2004 Difference $832,000 $761,000 $71,000 Actual property taxes paid in 2004, including 1 percent in lieu, were $797,000. The difference between the actual amount paid and the property taxes included in the 2004 cost of service, or $36,000, was set up on an after-tax basis as a debit deferral to be amortized into 2004 rates. Property taxes in 2005 are forecast to be 5.0 percent higher than actual property taxes paid in 2004, based on expected increases in assessed values and mill rates. Assessed values are continuing to increase at rates well above inflation as a result of the phase-in, through 2006, of new valuations for pipelines. The valuations for smaller diameter pipeline have been significantly increased relative to those in effect in The increases in assessed values are not being offset by reductions in mill rates in rural tax areas.

15 Tab Application Page 13 DEPRECIATION Test Year 2005 Decision /2004 Difference $1,069,000 $1,237,000 ($168,000) Depreciation expense is calculated using a fixed percentage rate times the gross plant cost, for each category of plant asset. The $168,000 decrease in depreciation from 2004 to 2005 reflects the reductions in depreciation expense relating to plant now fully depreciated, as well as a one time credit adjustment in the amount of $54,000 relating to transportation equipment that was over-depreciated in AMORTIZATION Test Year 2005 Decision /2004 Difference $3,000 $21,000 ($18,000) The details of the amortization expense for 2005 are provided under Tab 2. The 2004 to 2005 reduction in amortization expense is due to the size of the credit balance recorded in the short term interest deferral account in OTHER INCOME Test Year 2005 Decision /2004 Difference $153,000 $153,000 $0 The forecast of other income in 2005 is the same forecast used in 2004 as there was no compelling reason to change the forecast.

16 Tab Application Page 14 INCOME TAXES Test Year 2005 Decision /2004 Difference $483,000 $570,000 ($87,000) A number of items affect the determination of the income tax expense. The 2004 to 2005 reduction in depreciation and amortization expense has the most significant impact because these costs are non-deductible expenses and therefore have to be grossed up for income tax. RETURN ON COMMON EQUITY Test Year 2005 Decision /2004 Difference $1,093,000 $1,049,000 $44,000 The return on common equity component of the 2005 cost of service is higher than allowed under Decision 2004 primarily due to a higher absolute common equity figure as the rate base has increased from 2004 to The 2005 allowed ROE is decreasing from the approved 2004 level of 9.55 percent to 9.43 percent as determined in accordance with the Commission s automatic ROE adjustment mechanism. The lower 2005 ROE is more than offset by the impact of applying the 2005 ROE against a higher common equity dollar figure. CAPITAL STRUCTURE PNG(N.E.) is applying to maintain the deemed common equity component of the division at 36 percent. With the amortization of existing long-term loans from PNG combined with the growth in the division rate base, the long-term debt component of rate base is shrinking and the short-term debt component is growing. It was determined that these debt components remain in a reasonable range and therefore new long-term loans from PNG are not being proposed for 2005.

17 Tab Application Page 15 INTEREST EXPENSE Test Year 2005 Decision /2004 Difference Short-term Debt $302,000 $138,000 $164,000 Long-term Debt $1,190,000 $1,395,000 ($205,000) The interest expense on short-term debt has increased in 2005 over 2004 due solely to the increase in the short-term debt component of rate base; the interest rate on short-term debt is assumed to remain at 6.0 percent. Differences between the actual interest expense and the forecast expense arising as a result of differences in interest rates, will continue to be recorded in a deferral account. Long-term debt interest expense has declined for two reasons. First, the amount of long-term debt has declined due to amortization of existing loans. Second, the interest rates on the two RoyNat based loans to PNG(N.E.) are lower as a result of the 2005 forecast floating interest rates on the RoyNat loans being slightly less than the forecast fixed rate which was included in the division s 2004 approved revenue requirement. PNG(N.E.) proposes to continue to record the difference in interest expense arising as a result of the actual interest rates on the RoyNat loans varying from the forecast included in the 2005 revenue requirements. The interest rates on the RoyNat loans were not fixed in 2004 as applied-for by PNG and approved by the Commission since this would impose risks and costs on PNG in the event that these loans had to be retired earlier than scheduled which is anticipated to be the case if PNG s application to convert to an income trust is approved by the Commission.

18 Tab Application Page 16 COMPANY USE GAS COST Test Year 2005 Decision /2004 Difference $242,000 $180,000 ($62,000) The increase is primarily due to the expectation that gas supply prices will be higher in 2005 compared to the projected gas supply prices used to determine the 2004 provision for Company use gas costs. CAPITAL ADDITIONS IN 2005 Test Year 2005 Decision /2004 Difference $2,238,000 $2,206,000 $32,000 The capital budget for 2005 is almost the same as was budgeted for The capital additions for 2005 are consistent with 2004 as customer growth projections are similar and the degree of capital work required to maintain a safe and reliable pipeline system has not changed significantly.

19 Tab Application Page FORECAST GAS DELIVERIES The test year forecast of gas deliveries is one of the key components of the 2005 revenue requirements application as the forecast determines the projected amount of revenue PNG(N.E.) will receive from its customers during 2005 to pay its cost of serving those customers. The gas deliveries forecast for each customer class is discussed below. Residential and Small Commercial Firm Sales Customers The following provides a series of figures to demonstrate the reasonableness of the forecast of 2005 deliveries to the residential and small commercial customers in each of the Fort St. John and Dawson Creek Divisions. Fort St. John Forecast 2005 Deliveries Fort St. John (GJ s) Customer Class Test Year 2005 Decision 2004 Normalized 2004 Normalized 2003 Normalized 2002 Residential Small Commercial Customer Class Fort St. John Normalized Use per Account (GJ/Customer) Linear Trend 2005 Test Year 2005 Decision 2004 Projected Actual 2004 * 2003 Residential Small Commercial *Projected 2004 is the sum of normalized deliveries to the end of October 2004 plus budgeted deliveries for November and December 2004.

20 Tab Application Page 18 It is PNG(N.E.) s practice to set the test year use per account figure at the midpoint between the normalized Projected 2004 and Linear Trend 2005 figures. PNG(N.E.) does not see any reason to depart from this practice for the 2005 test year forecast. Similarly, the small commercial customer forecast is usually set at the mid-point use per account between Projected 2004 and the Linear Trend 2005 figures. This appears to generate a forecast that looks reasonable having regard to historical normalized deliveries and it reflects the higher projected use per account for The customer account statistics are provided in the following Table: Customer Class Weighted Average for Test Year 2005 Fort St. John Customer Counts Projected Year-end 2004 Decision 2004 Weighted Average Year-end 2003 Residential Small Commercial The Decision 2004 forecast is compared to actual deliveries for 2004, 2003, 2002 and 2001 in the following table: Customer Class Decision 2004 Projected Actual 2004 * Fort St. John (GJ s) Actual 2003 Actual 2002 Actual 2001 Residential Small Commercial * Projected actual 2004 is the sum of actual deliveries to the end of October 2004 plus budgeted deliveries for November and December 2004.

21 Tab Application Page 19 Dawson Creek Forecast 2005 Deliveries Customer Class Test Year 2005 Dawson Creek (GJ s) Decision 2004 Normalized 2004 Normalized 2003 Normalized 2002 Residential Small Commercial Customer Class Dawson Creek Normalized Use per Account (GJ/Customer) Linear Trend 2005 Test Year 2005 Decision 2004 Projected Actual 2004 * 2003 Residential Small Commercial *Projected 2004 is the sum of normalized deliveries to the end of October 2004 plus budgeted deliveries for November and December The test year 2005 use per account figures are the midpoint between the Projected 2004 and Linear Trend 2005 figures. The lump sum forecasts for 2005 determined on this basis are consistent with the historical total annual deliveries.

22 Tab Application Page 20 The customer account statistics are provided in the following Table: Customer Class Weighted Average for Test Year 2005 Dawson Creek Customer Counts Projected Year-end 2004 Decision 2004 Weighted Average Year-end 2003 Residential Small Commercial The Decision 2004 forecast is compared to actual deliveries for 2004, 2003, 2002 and 2001 in the following table: Customer Class Decision 2004 Dawson Creek (GJ s) Projected Actual 2004 * Actual 2003 Actual 2002 Actual 2001 Residential Small Commercial * Projected Actual 2004 is the sum of actual deliveries to the end of October 2004 plus budgeted deliveries for November and December 2004.

23 Tab Application Page 21 Other Core Market Customers The following summarizes the projected 2005 deliveries to the large commercial firm, small industrial sales and transportation service customers for both divisions in comparison to information on 2004 deliveries. Customer Class Fort St. John (GJ s) Test Year 2005 Decision 2004 Projected Actual 2004 * Large Commercial Small Ind. Sales Small Industrial T-Service * Projected Actual 2004 is the sum of actual deliveries to the end of October 2004 plus budgeted deliveries for November and December Customer Class Dawson Creek (GJ s) Test Year 2005 Decision 2004 Projected Actual 2004 * Large Commercial Small Ind. Sales (one account) Small Industrial T-Service No T-Service Customers in Dawson Creek * Projected Actual 2004 is the sum of actual deliveries to the end of October 2004 plus budgeted deliveries for November and December The above forecasts for 2005 are based on a review of historical deliveries to these customer classes and expected use in 2005 based on discussions with the customers. Given the relatively few number of customers in the above classes, PNG(N.E.) considers its 2005 forecast based on discussions with each of the customers to be reasonable. The forecast of deliveries to the small industrial customer in Dawson Creek is subject to a deliveries deferral account in view of the year to year volatility of deliveries to this customer.

24 Tab Application Page 22 RATE MATTERS Allocation of Revenue Deficiency PNG(N.E.) has allocated the 2005 revenue deficiency to its customers using the projected 2005 gross margin by customer class as the allocator. This is consistent with the methodology approved by the Commission over the past several years. Derivation of Forecast Test Year Gas Deliveries and Gross Margin PNG(N.E.) has included under Tab Rates detailed schedules showing the derivation of the forecast test year gas deliveries by applying the forecast use per account to the forecast weighted average number of customers in the case of the residential and small commercial customers. For completeness the forecast deliveries to the other customers is also shown. The split between sales and transportation service deliveries is also shown. This enables the reader to balance the figures shown on Schedule 1, Tab 1 for sales and transportation service with the corresponding figures shown under Tab Rates. Similarly, the derivation of projected margin recovery in the test year using current rates is shown on schedules included in Tab Rates to verify the figures provided in the summary sheets. There may be some small differences between the detailed schedules and the summary schedules due to rounding that occurs when utilizing large spreadsheets to calculate gross revenue, delivery margin and gas supply costs.

25 Tab Application Page 23 RSAM Rate Riders The Summary of Proposed Rates Effective January 1, 2005 shows a separate line for the 2005 RSAM rate rider which is based on recovering the projected December 31, 2004 RSAM balance in equal amounts over the 2005 to 2007 three year period. The derivation of the 2005 RSAM rate rider is provided below. Actual RSAM Balance 12/31/03 Recovery of RSAM in 2004 to 10/31/04 RSAM Deferral in 2004 to 10/31/04 Forecast RSAM Deferral Nov/Dec 2004 Forecast RSAM Balance 12/31/04 Residential Small Commercial Total $67,370 $62,809 $130,179 (21,730) (16,737) (38,466) 113,606 (10,629) 102, $159,247 $35,443 $194,690 Years of Amortization Projected 2005 Amortization of RSAM Balance Divided by Forecast 2005 Deliveries $53,082 $11,814 $64, GJ GJ GJ 2005 RSAM Rate Rider $0.031/GJ $0.009/GJ $0.022/GJ

26 Tab Application Page /2005 Gas Supply Cost Charge Changes/GCVA Riders For the purposes of this Application, the gas supply cost recovery rates were recalculated using PNG(N.E.) s gas cost flow through model updated to reflect the 2004/2005 gas supply price arrangement changes with PNG(N.E.) s gas suppliers and the forward gas price strip as of November 24, Gas prices forecast in the November 24, 2004 forward gas price strip are higher than the forecast prices in the June 8, 2004 forward gas price strip which was used to set the gas commodity rates effective July 1, 2004, the last time the gas supply charge rates were changed. Also, the fixed gas prices negotiated by PNG for its 2004/2005 seasonal gas supply requirements are on average higher than the projected gas prices currently embedded in rates. The gas supply cost rates proposed by PNG effective January 1, 2005 reflect the impact of the higher forecast 2005 gas supply costs. The gas supply cost rates proposed in this Application are the same as those proposed in PNG s fourth quarter 2004 gas supply cost report to the Commission that was filed in early December Determination of 2005 Unit Company Use Gas Cost Rate The 2005 projected cost of Company use gas is based on the forecast gas prices in the applicable forward gas price strip and the quantity of gas PNG(N.E.) expects to purchase for Company use. The calculation of the unit Company use gas cost recovery rate is shown on a schedule under Tab Rates. PNG(N.E.) divides the forecast cost of Company use gas to be supplied by PNG(N.E.) by total deliveries to all customers to determine the recovery rate to be embedded in rates. Bill Comparison from December 2004 to January 2005 Fort St. John The average rate increase for residential customers is 5.8 percent and for small commercial customers is 5.3 percent. The average residential rate in 2005 is about $10.40/GJ. This is approximately $2.21/GJ less than the equivalent electricity rate of $12.61/GJ assuming a 75 percent efficiency rating for natural gas compared to electricity. Similarly, the small commercial customer average unit rate is $9.64/GJ. This is about $5.47/GJ less than the equivalent electricity rate of $15.11/GJ assuming an 80 percent efficiency factor for natural gas compared to electricity. Consequently, natural gas in Fort St. John has about a 18 percent and 36 percent price advantage over electricity relative to residential and small commercial customers, respectively.

27 Tab Application Page 25 Dawson Creek The average rate increase is 5.7 percent for both residential small commercial customers. The average residential rate in 2005 is about $10.24/GJ. This is approximately $2.37/GJ less than the equivalent electricity rate of $12.61/GJ assuming a 75 percent efficiency rating for natural gas compared to electricity. Similarly, the small commercial customer average unit rate is $9.09/GJ. This is about $6.02/GJ less than the equivalent electricity rate of $15.11/GJ assuming an 80 percent efficiency factor for natural gas compared to electricity. Consequently, natural gas in Dawson Creek has about a 19 percent and 40 percent price advantage over electricity relative to residential and small commercial customers, respectively. OTHER PNG(N.E.) hereby requests approval of a deferral account to record the difference between budgeted unaccounted for gas and actual unaccounted for gas losses/gains. The PNG-West Division has a deferral account in place for this purpose and PNG(N.E.) considers a deferral account should be approved for its Fort St. John/Dawson Creek Division to be consistent with the PNG-West Division. Unaccounted for gas is by its nature difficult to control and it is in PNG(N.E.) s and the customers best interests for these volumes to be minimized. PNG(N.E.) will continue to diligently account for its gas receipts and deliveries to minimize the level of unaccounted for gas. REGULATORY SCHEDULES 1 TO 5 The following regulatory schedules are included under Tabs 1 to 5: Tab 1 - Utility Income & Return Tab 2 - Utility Rate Base Tab 3- Income Taxes Tab 4 - Common Equity Tab 5 - Return on Capital A revised set of regulatory schedules will be filed in February 2005 after the actual results for 2004 are released to the general public.

28 Tab Application Page 26 INTERIM RATES EFFECTIVE JANUARY 1, 2005 PNG(N.E.) hereby applies for Commission approval of interim rates effective January 1, 2005 at the level proposed in the Table entitled Summary of Proposed Rates Effective January 1, 2005 as set forth under Tab Rates. If the permanent rates ultimately approved by the Commission differ from the interim rates, then PNG(N.E.) will rebill its customers at the permanent rates back to January 1, 2005 to ensure all of PNG(N.E.) s customers pay only the approved rates throughout the test year. All of which is respectfully submitted DATED at Vancouver, British Columbia this 17th day of December PACIFIC NORTHERN GAS (N.E.) LTD. R.G. Dyce President & Chief Executive Officer All notices and other communications in connection with this Application should be directed to: C.P. Donohue Director, Regulatory Affairs and Gas Supply Pacific Northern Gas (N.E.) Ltd. # West Georgia Street Vancouver, British Columbia V6E 4E6 Telephone: (604) Fax: (604) cdonohue@png.ca

29 Pacific Northern Gas (N.E.) Ltd. (Fort St. John Division) Summary of Proposed Rates Effective January 1, 2005 ($/GJ unless otherwise specified) Tab Rates Page 1 Customer Class Residential (RS1) Rates Effective December 31, Revenue Requirement 2004 / 2005 Gas Supply Cost Charge Proposed Rates January 1, 2005 Proposed Rate Changes Monthly Fixed Charge $7.00 $7.00 $0.00 Delivery Charge Gas Supply Charge GCVA Commodity Rider RSAM Small Commercial (RS2) Monthly Fixed Charge $7.00 $7.00 $0.00 Delivery Charge Gas Supply Charge GCVA Commodity Rider RSAM Large Commercial (RS3) Small Industrial (RS4) Monthly Fixed Charge $ $ $0.00 Delivery Charge Gas Supply Charge GCVA Commodity Rider Monthly Fixed Charge $ $ $0.00 Delivery Charge Gas Supply Charge GCVA Commodity Rider Small Industrial Service (RS5) Monthly Fixed Charge $ $ $0.00 Delivery Charge Small Industrial Service (RS6) Monthly Fixed Charge $ $ $0.00 Delivery Charge Small Industrial Service (RS7) Monthly Fixed Charge $3, $3, $0.00 Delivery Charge Authorized Overrun Gas Supply Charge GCVA Commodity Rider Small Industrial Service (RS9) Monthly Fixed Charge $8, $8, $0.00 Delivery Charge Small Industrial Service (RS10) Monthly Fixed Charge $3, $3, $0.00 Delivery Charge Small Industrial Service (RS11) Monthly Fixed Charge $3, $3, $0.00 Delivery Charge Rate Schedules.xls FSJ 12/16/2004

30 Tab Rates Page 2 Pacific Northern Gas (N.E.) Ltd. (Dawson Creek Division) Summary of Proposed Rates Effective January 1, 2005 ($/GJ unless otherwise specified) Customer Class Rates Effective December 31, Revenue Requirement 2004 / 2005 Gas Supply Cost Charge Proposed Rates January 1, 2005 Proposed Rate Changes Residential (RS1) Monthly Fixed Charge $7.00 $7.00 $0.00 Delivery Charge Gas Supply Charge GCVA Rider RSAM Small Commercial (RS2) Monthly Fixed Charge $7.00 $7.00 $0.00 Delivery Charge Gas Supply Charge GCVA Rider RSAM Large Commercial (RS3) Monthly Fixed Charge $ $ $0.00 Delivery Charge Gas Supply Charge GCVA Rider Small Industrial (RS4) Monthly Fixed Charge $ $ $0.00 Delivery Charge Gas Supply Charge GCVA Rider Rate Schedules.xls DC 12/16/2004

31 Tab Rates Page 3 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division) Bill Comparison December 2004 to January 2005 FORT ST. JOHN AREA Permanent Rates Annual Bill Proposed Rates Annual Bill Annual Bill Customer Classification Dec. 31, 2004 Estimate Jan. 1, 2005 Estimate Difference Annual Use $ / GJ $ $ / GJ $ $ % Residential: GJ Monthly Fixed 7.00 / mo Delivery Charge RSAM Rider % Gas Supply Charge GCVA Rider % $9.842 /GJ $1, $ /GJ $1, $ % Small Commercial: GJ Monthly Fixed 7.00 / mo Delivery Charge , , RSAM Rider , , % Gas Supply Charge , , GCVA Rider , , % $9.156 /GJ $5, $9.644 /GJ $5, $ % 05-Billcomparisons.xls FSJ Bill Comp

32 Tab Rates Page 4 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division) Bill Comparison December 2004 to January 2005 DAWSON CREEK AREA Permanent Rates Annual Bill Proposed Rates Annual Bill Annual Bill Customer Classification Dec. 31, 2004 Estimate Jan. 1, 2005 Estimate Difference Annual Use $ / GJ $ $ / GJ $ $ % Residential: GJ Monthly Fixed 7.00 / mo Delivery Charge RSAM Rider % Gas Supply Charge GCVA Rider % $9.683 /GJ $1, $ /GJ $1, $ % Small Commercial: GJ Monthly Fixed 7.00 / mo Delivery Charge , RSAM Rider , , % Gas Supply Charge , , GCVA Rider , , % $8.606 /GJ $5, $9.094 /GJ $6, $ % 05-Billcomparisons.xls DC Bill Comp

33 Tab Rates Page 5 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division) SUMMARY OF DELIVERY CHARGE PROPOSED RATE CHANGES EFFECTIVE JANUARY 1, Allocation of Test Year Gross Revenue Rate Changes Customer Classification Gas Deliveries Margin Deficiency for Rev. Def. (GJ) ($) ($) ($/GJ) Residential (RS1) ,787, , Commercial Small Commercial (RS2) ,479,322 66, Large Commercial Firm (RS3) ,553 11, Total Commercial ,903,875 78,383 Small Industrial Sales (RS4) ,370 6, Total Sales ,930, ,064 Industrial Transport RS ,877 1, RS ,600 5, RS ,120 2, RS n.a. RS ,523 3, RS ,703 10, RS ,985 1, Total Transport ,808 25,232 TOTAL , Ratech.xls FSJDC Rev Req 12/16/2004

34 Tab Rates Page 6 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division) SUMMARY OF REVENUE, COST OF GAS, GROSS MARGIN TEST YEAR 2005 Allocated 2005 Test Year Cost of Gross Revenue Customer Classification Gas Deliveries Revenue Gas Margin Deficiency (GJ) ($) ($) ($) ($) Residential (RS1) ,787, ,221 Commercial Small Commercial (RS2) ,479,322 66,923 Large Commercial Firm (RS3) ,553 11,460 Small Industrial Sales (RS4) ,370 6,461 Total Sales Industrial Transport RS ,877 1,805 RS ,600 5,550 RS ,120 2,675 RS RS ,523 3,415 RS ,703 10,411 RS ,985 1,376 Total Transport TOTAL ,676, , Ratech.xls FSJDC REV, COG, MARGIN 12/16/2004

35 Pacific Northern Gas (N.E.) Ltd. (Fort St. John / Dawson Creek Division) Tab Rates Page 7 Derivation of Test Year Forecast Gas Deliveries FORT ST. JOHN Test Year 2005 Test Year Test Year Average Test Year Customer Count Net Customer Weighted Average Use Per Account Deliveries Customer Classification At Dec. 31st, 2004 Additions Customer Count (GJ) (GJ) Sales: Residential (Rate 1 ) , ,074,915 Commercial Small Commercial (Rate 2) 1, , ,834 Large Commercial Firm (Rate 3) ,152 Total Commercial 1, , ,986 Small Industrial Sales (RS4) ,901 Subtotal Sales 2,192,802 Industrial Transport 2005 Test Year Gas Sales (GJ) RS5 84,999 RS6 192,501 RS7 299,998 RS8 0 RS9 64,999 RS10 560,299 RS11 75,000 Subtotal Transport 1,277,796 Total 3,470,598 DAWSON CREEK Test Year 2005 Test Year Test Year Average Test Year Customer Count Net Customer Weighted Average Use Per Account Deliveries Customer Classification At Dec. 31st, 2004 Additions Customer Count (GJ) (GJ) Sales: Residential (Rate 1 ) , ,879 Commercial Small Commercial (Rate 2) ,325 Large Commercial Firm (Rate 3) ,098 Total Commercial ,423 Small Industrial Sales (RS4) ,498 Total 1,319,800

36 Tab Rates Page 8 Pacific Northern Gas (N.E.) Ltd. (Fort St. John / Dawson Creek Division) Derivation of Test Year Forecast Gross Margin 2005 Current Weighted Total Fort St. John Test Year Delivery Avg. Delivery Test Year Deliveries Charge Delivery Customer Current Fixed Charge & Fixed Charge Gross Customer Classification (GJ) $ / GJ Margin Count Fixed Charge Margin Margin Margin Sales: Residential (Rate 1 ) 1,074, ,403,510 8,348 * ,232 3,104,742 3,104,742 Commercial Small Commercial (Rate 2) 817, ,634,032 1, ,408 1,748,440 1,748,440 Large Commercial (Rate 3) 138, , , , ,173 Total Commercial 955,986 1,845,405 1, ,208 1,988,613 1,988,613 Small Industrial (Rate 4) 161, , , , ,032 Subtotal Sales 2,192,802 4,367, ,960 5,241,387 5,241,387 Transportation: 2005 Current Weighted Total Test Year Delivery Avg. Delivery Test Year Deliveries Charge Delivery Customer Current Fixed Charge & Fixed Charge Gross (GJ) $ / GJ Margin Count Fixed Charge Margin Margin Margin Rate 5 84, , ,920 66,876 66,876 Rate 6 192, , , , ,601 Rate 7 299, , , ,000 99,120 99,120 Rate , Rate 9 64, , , , , ,523 Rate , , , , , ,703 Rate 11 75, , , ,140 50,985 50,985 Subtotal Transportation 1,277, , , , ,808 Total Fort St. John 3,470,598 4,794,971 1,381,224 6,176,195 6,176, Current Weighted Total Dawson Creek Test Year Delivery Avg. Delivery Test Year Deliveries Charge Delivery Customer Current Fixed Charge & Fixed Charge Gross Customer Classification (GJ) $ / GJ Margin Count Fixed Charge Margin Margin Margin Sales: Residential (Rate 1 ) 615, ,255,161 5,071 * ,964 1,681,125 1,681,125 Commercial Small Commercial (Rate 2) 460, , , , ,999 Large Commercial (Rate 3) 162, , , , ,180 Total Commercial 622, , , , ,179 Small Industrial (Rate 4) 81, , ,840 91,338 91,338 Subtotal Sales 1,319,800 2,168, ,268 2,689,642 2,689,642 Total Dawson Creek 1,319,800 2,168, ,268 2,689,642 2,689,642 * The weighted average customer count for determination of the monthly fixed charge revenue varies from the weighted avearage customer count used for forecasting gas deliveries due to the application of month end customers each month to the $ 7.00 monthly fixed charge

37 Tab Rates Page 9 Pacific Northern Gas (N.E.) Ltd. (Fort St. John / Dawson Creek Division) Derivation of Test Year Forecast Gross Margin 2005 Current Weighted Total FSJ / DC Combined Test Year Delivery Avg. Delivery Test Year Gas Sales Charge Delivery Customer Current Fixed Charge & Fixed Charge Gross Customer Classification (GJ) $ / GJ Margin Count Fixed Charge Margin Margin Margin Sales: Residential (Rate 1 ) 1,690,794 3,658,671 13, ,127,196 4,785,867 4,785,867 Commercial Small Commercial (Rate 2) 1,278,159 2,306,567 2, ,872 2,479,439 2,479,439 Large Commercial (Rate 3) 300, , , , ,353 Total Commercial 1,578,409 2,677,120 2, ,672 2,905,792 2,905,792 Small Industrial (Rate 4) 243, , , , ,370 Subtotal Sales 3,512,602 6,535,801 1,395,228 7,931,029 7,931,029 Transportation: 2005 Current Weighted Total Test Year Delivery Avg. Delivery Test Year Gas Sales Charge Delivery Customer Current Fixed Charge & Fixed Charge Gross (GJ) $ / GJ Margin Count Fixed Charge Margin Margin Margin Rate 5 84, , ,920 66,876 66,876 Rate 6 192, , , , ,601 Rate 7 299, , , ,000 99,120 99,120 Rate , Rate 9 64, , , , , ,523 Rate , , , , , ,703 Rate 11 75, , , ,140 50,985 50,985 Subtotal Transportation 1,277, , , , ,808 Total Fort St. John / Dawson Creek 4,790,398 6,963,345 1,902,492 8,865,837 8,865,837

38 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division) Determination of Gas Supply Cost Rate Changes Effective January 1, 2005 Using Nov. 24th, 2004 Forward Gas Strip Customer Classification Gas Supply Costs Rates Gas Supply Costs Proposed Rates Proposed Rate Changes Effective July 1, 2004 Effective January 1, 2005 Effective January 1, 2005 Company Company Gas Company Demand Commodity Total Use Gas Demand Commodity Total Use Gas Supply Use Gas ($/GJ) ($/GJ) D&C ($/GJ) ($/GJ) ($/GJ) D&C ($/GJ) ($/GJ) ($/GJ) Residential (RS1) Small Commercial (RS2) Large Commercial (RS3) Small Industrial (RS4) Company Use Transportation Service FSJ-DC Retail Rate Changes 05-FSJ-DC.xls

39 Tab Rates Page 11 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division) ALLOCATION OF DEMAND CHARGES EFFECTIVE JANUARY 1, 2005 Customer Classification Peak Day Allocation of 2005 Annual Unit Demand Requirement Demand Charges Requirements Charge (GJ) (%) ($) (GJ) ($/GJ) Residential (RS1) % 966, Small Commercial (RS2) % 760, Large Commercial (RS3) % 130, Industrial Sales (RS4) % 63, Company Use Gas % 13, Total % 1,933, FSJ-DC.xls FSJ-DC Demand Chrg Allocation 12/16/2004

40 Tab Rates Page 12 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division) Calculation of 2005 Unit Company Use Gas Cost 2005 Commodity Cost $219,145 B.C.S.S. Tax $8,711 Demand Cost $13,729 Total Co. Use Gas Cost $241,585 Total Company use gas requirement GJ Deliveries GJ 2005 Unit Company Use Gas Cost Rate $0.050 /GJ $241, Commodity Cost of Company Use Gas per GJ Purchased $6.591 /GJ $219, FSJ-DC.xls FSJ-DC Company Use 12/16/2004

41 Tab Rates Page 13 Pacific Northern Gas (N.E.) Ltd. (Fort St. John/Dawson Creek Division) Forward Gas Price Strip Nov. 24th, 2004 STATION #2 AECO CDN$/GJ CDN$/GJ Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Average