pacific northern gas (n.e.) ltd....customer care 466 395 71 325 315 293 322 712 meter reading 187...

PACIFIC NORTHERN GAS (N.E.) LTD.

(Fort St. John/Dawson Creek Division) and

(Tumbler Ridge Division)

2009 Revenue Requirements Applications

to the

B.C. Utilities Commission

November 27, 2008

B-1

ylapierr

NE - 2009 RR


(Fort St. John/Dawson Creek Division)

2009 Revenue Requirements Application

to the


November 27, 2008

Pacific Northern Gas (N.E.) Ltd.


2009 REVENUE REQUIREMENTS APPLICATION

November 27, 2008

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

Tab Application FSJ/DC 2009 Rate App. Page 1

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996,

c. 473, as amended

- and -

In The Matter Of




November 27, 2008 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 (“FSJ/DC”) division in accordance with this Application, effective January 1, 2009. 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. The following narrative provides the submissions by PNG(N.E.) in support of the applied for rates effective January 1, 2009.


INTRODUCTION PNG(N.E.)’s 2009 revenue requirements Application sets out PNG(N.E.)’s budgeted 2009 costs and forecast revenues using currently approved rates and forecast 2009 gas deliveries. The extent to which forecast revenues vary from forecast costs determines whether PNG(N.E.) is seeking Commission approval of rate increases or decreases for the Fort St. John/Dawson Creek division. PNG(N.E.) compares its forecast 2009 costs to the Commission approved negotiated settlement of PNG(N.E.)’s 2008 revenue requirements application (“NSP 2008”) to put the 2009 figures in context. The forecast 2009 calendar year figures are identified in this Application under the heading “Test Year 2009”. The following regulatory financial schedules are included under Tabs 1 to 5 of this Application:

• Tab 1 - Utility Income & Return

• Tab 2 - Utility Rate Base

• Tab 3 - Income Taxes

• Tab 4 - Common Equity

• Tab 5 - Return on Capital The regulatory schedules compare the Test Year 2009 figures to the NSP 2008 figures. A Table is provided on the next page comparing the Test Year 2009 cost of service described in this Application to the NSP 2008 cost of service approved by the Commission. A higher Test Year 2009 cost of service compared to NSP 2008 and higher forecast gas deliveries in 2009 with corresponding higher revenues results in a net projected revenue deficiency in 2009. Consequently, PNG(N.E.) is applying for Commission approval to increase its rates effective January 1, 2009.


Test Year NSPEXPENSES 2009 2008 Total Subtotal

OperatingLabour 1,492 1,378 114 Other 2,312 2,173 139 Sub-total 3,803 3,550 253

MaintenanceLabour 71 108 (37) Other 152 182 (30) Sub-total 223 290 (67)

Administrative and GeneralLabour 0 0 0 Total Company Benefits 463 474 (12) Other 1,124 996 129 Sub-total 1,587 1,470 117

Total (O, M, A & G) Excluding Co. Use 5,613 5,310 303 303

Transfers to Capital Operating (208) (200) (8)

Transfers to Capital Admin. & Gen. (216) (205) (11)

Property Taxes 977 958 19

Depreciation 1,439 1,349 90

Amortization (49) (216) 167

Other Income (179) (171) (8) 249

Total Expenses Excluding Co, Use 7,377 6,825 552 552

Income Taxes 288 277 11

Return on Common Equity 1,129 1,087 41

Short Term Debt 100 56 44

Long Term Debt 1,179 1,493 (315) (218)

Total Cost of Service Excluding Co. Use 10,072 9,738 334 334

Company Use Gas 544 510

Total Cost of Service Including Co. Use 10,616 10,248

2008 to 2009 Cost of Service Increase (Decrease) 334

2008 to 2009 Margin Decrease (Increase) (167)

2009 Revenue Deficiency (Sufficiency) 167

Difference

Test Year 2009 vs. NSP 2008COST OF SERVICE COMPARISON

($000)


The major components of the Test Year 2009 cost of service are summarized below in comparison to the corresponding figures under NSP 2008. The Table shows the main drivers of the projected revenue deficiency in 2009.

$000’s Cost of Service Item Test Year

2009 NSP 2008

2009/2008 Difference

Operating, Maintenance, Administrative and General Expenses $5,613 $5,310 $303

Transfers to Capital, Operating, Administrative and General (424) (405) (19)

Other Cost of Service items including property taxes and depreciation 2,189 1,920 269

Return components including return on equity, income taxes and debt costs 2,695 2,913 (218)

Cost of Service Ex. Co. Use Gas Cost $10,072 $9,738 $334

Margin Using 2008 Rates $9,905 $9,738 ($167)

Total Test Year 2009 Revenue Deficiency $167

Total Cost of Service Ex. Co. Use Gas $10,072 $9,738 Company use gas cost pass through 544 510

Total Cost of Service including Company Use Gas Cost $10,616 $10,248

The following explains in detail the various components of PNG(N.E.)’s FSJ/DC division Test Year 2009 cost of service as summarized above. Of note are two significant cost increases. Depreciation expense is higher by $90,000 and a depreciation credit adjustment deferral account of $294,000 was fully amortized in 2008. The cessation of this credit deferral account is the main reason why amortization expense is increasing by $167,000 in 2009 compared to 2008. These two items alone account for $257,000 of the $334,000 cost of service increase from 2008 to 2009.


OPERATING EXPENSES The Table below sets forth historical operating expenses in comparison to the Test Year 2009 applied for amounts.

$000’s BCUC

Account Test Year

2009 NSP 2008

2009/08 Difference

Actual 2007

Actual 2006

Actual 2005

Actual 2004

670 – Supervision $441 $361 $80 $435 $375 $232 $115

675 – Mains and Services 311 290 21 306 268 255 224

685 – General Operations 190 246 (56) 221 236 283 429

688 – Other General Operations

530 470 60 459 466 391 469

711/713/714 Customer Care

466 395 71 325 315 293 322

712 Meter Reading

187 175 12 175 177 153 139

Add Shared Service Costs 1,007 928 79 844 829 735 674

718 Uncollectible Accounts

159 156 3 153 150 198 191

Other Including 673 Expenses

512 529 (17) 456 392 464 448

Subtotal $3,803 $3,550 $253 $3,374 $3,208 $3,004 $3,012

Transfers to Capital (208) (200) (8) (192) (193) (177) (239)

Operating Expenses Excluding Co. use gas cost

$3,595 $3,350 $245 $3,182 $3,015 $2,827 $2,773


The figures in the above Table 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 following provides more detailed information on NSP 2008 to Test Year 2009 changes in operating costs as summarized by Commission Account number in the above Table. Account 670 The expenses in Account 670 are for the costs of supervision related to distribution system operations activities. Costs related to emergency standby ($16,000) and janitorial services ($25,000) are now being budgeted under Account 670 instead of in Account 685. The other major reason for the increase in Account 670 is rising labour costs ($30,000) to reflect the increased level of planning and coordinating of activities required both internally and externally. Account 675 The forecast expenditures in the distribution mains Account 675 for 2009 ($311,000) are consistent with those actually incurred in 2007 ($306,000) and expected in 2008. This reflects continued strong level of general construction activity. Account 685 The decrease in Account 685 results from budgeting emergency standby and janitorial expenses in Account 670 in 2009 as noted earlier plus a variety of other forecast cost reductions. Account 688 The forecast expenditures in the other general operations Account 688 are increasing in 2009 compared to 2008 due to three factors. An increase in automotive expense (fuel) of $13,000 is one factor, with an increase in training labour costs of $11,000 being the second factor. The increase in allowable time-off labour costs accounts for the remainder of the increase. Account 711/713/714 The increase in costs for Customer Care reflects the impact of PNG renewing its contract with its billing system application service provider. The original contract had been in place since 1999 and the new contract reflects current market rates and conditions.


MAINTENANCE COSTS

$000’s BCUC

Account Test Year

2009 NSP2008


Actual 2007

Actual 2006

Actual 2005

Actual 2004

867 Reg. Stations $39 $67 ($28) $24 $27 $44 $8

875 Mains/Services 102 102 0 158 65 196 162

878 Meters 47 56 (9) 27 45 59 81

All other 35 65 (30) 18 12 63 65

Total $223 $290 ($67) 227 $149 $362 $316 The forecast expenditures for transmission regulator stations are decreasing by $28,000 to reflect recent actual costs required to maintain the stations throughout the Fort St. John/Dawson Creek service area. Meter repair costs in Account 878 are forecast to be $9,000 lower in 2009 as it is anticipated that fewer of the recalled meters will be able to be repaired due to reaching the end of their useful life and therefore will be uneconomical to repair. This reduces the repair cost budget accordingly. These meters will be discarded and new meters will be purchased. PNG(N.E.)’s overall 2009 planned maintenance activities at a budgeted cost of $223,000 are responsive to system needs and are at a level PNG(N.E.) considers will ensure PNG(N.E.)’s facilities are kept in good working order and ensure continued safe, reliable and secure gas delivery service to its customers.


ADMINISTRATIVE AND GENERAL COSTS

$000’s Cost Element Test Year

2009 NSP 2008


Actual 2007

Actual 2006

Actual 2005

Actual 2004

721 Administration

$2

$4

($2)

$4

$2

$7

$6

Add 721 Shared Service Costs

751

664

87

641

592

481

500

722 Audit/Legal Fees

81

58

23

26

32

15

15

723 Insurance

142

136

6

132

137

161

126

725 Employee Ben.

463

474

(11)

490

486

407

410

728 General

42

41

1

41

45

51

46

Add 728 Shared Service Costs

106

93

13

92

86

0

0

Sub-total

1,587

1,470

117

1,426

1,380

1,122

$1,103

Less: Transfers to Capital

(216)

(205)

(11)

(217)

(201)

(163)

($177)

Total

$1,371

$1,265

$106

$1,209

$1,179

$959

$926

Administrative and general costs, net of transfers to capital, have increased from $1,265,000 under NSP 2008 to $1,371,000 in Test Year 2009, an increase of $106,000. The increase reflects higher administrative shared services charged by PNG (i.e. the parent company of PNG(N.E.)) under Account 721 of $87,000 and higher shared service costs of $13,000 for Account 728. The higher Account 721 costs reflect head office cost increases for PNG for a staff addition to comply with more detailed financial and corporate reporting requirements. Account 728 costs are increasing to reflect corresponding increases faced by PNG. Account 722 costs have increased from $58,000 to $81,000 due to higher audit fees as a result of quarterly reviews being performed by PNG(N.E.)’s external auditors.


SHARED SERVICE CHARGES BY PNG TO PNG(N.E.)

The PNG-West 2009 revenue requirements application narrative contains a detailed description of how PNG determines what it charges PNG(N.E.) for services provided by PNG to PNG(N.E.). The PNG-West evidence is incorporated into this Application by reference. The following Table summarizes the shared service charges allocated by PNG to PNG(N.E.)’s Fort St. John/Dawson Creek division over the 2005 to 2009 period.

$000’s

Costs Allocated Test Year 2009

NSP 2008

2009/08 Change

Actual 2007

Actual 2006

Actual 2005

721 Administration

Benefits

$619 132

$543 121

$76 11

$513125

$478 114

$39486

685 General Ops.

Benefits

361 88

324 82

37 6

26074

278 73

24160

711/713/714 Customer Care

Benefits

463 95

432 90

31 5

41198

386 93

36272

728 Corporate

106

93

13 92

84 0

Total Allocated

Benefits

1,549

315

1,392

293

157 22

1,275297

1,226

280 998218

Total

$1,864

$1,685

$179 $1,573

$1,506 $1,215

Shared service charges by PNG to PNG(N.E.)’s FSJ/DC division are projected to increase in 2009 from 2008 levels primarily due to cost increases facing PNG. The reason for the cost increases are provided in the PNG-West 2009 revenue requirements application.


TRANSFERS TO CAPITAL

$000’s

Cost Element Test Year 2009

NSP 2008

2009/08 Difference

Actual 2007

Actual 2006

Actual 2005

Operating $208 $200 $8 $192 $193 $177

Administration $216 $205 11 $217 $201 $163

% of Overhead Allocated

17.81% 17.96% (0.15%) 18.6% 18.6% 18.8%

The allocation of overhead to capital projects for 2009 has been calculated using a rate of 17.81 percent, compared to 17.96 percent under NSP 2008. The transfer to capital rate is based upon the budgeted component of direct labour in capital projects expected to be completed during the year. PNG(N.E.) is requesting Commission approval to fix the transfer rate for 2009 at 17.81 percent of actual overhead expenses. This figure will be updated when the final 2009 regulatory schedules are filed with the Commission. PROPERTY TAXES

$000’s Cost

Element Test Year

2009 NSP 2008


Actual 2008

Actual 2007

Actual 2006

Property Taxes $754 $698 ($57) $733 $670 $698

1% in Lieu 223 260 (73) 260 217 260

Total $977 $958 (130) $993 $887 $958

Actual 2008 property taxes were higher than forecast under NSP 2008. The Test Year 2009 provision is based on a 3 percent increase over actual 2008 property taxes having regard to the Province’s freeze on assessed values, additions of new property and inflation adjustments in mill rates. The 1 percent in lieu tax is based on revenues received in 2007.


DEPRECIATION

Test Year 2009 NSP 2008 2009/2008 Difference

$1,439,000 $1,349,000 $90,000

Depreciation expense is calculated using the applicable fixed percentage rate times the gross plant cost, for each category of plant asset. The increase in depreciation from 2008 to 2009 is primarily due higher gross plant subject to depreciation. Specifically, gross plant is projected to total $67,454,000 at year end 2009 compared to $64,761,000 at year end 2008, an increase of $2,693,000. AMORTIZATION

Test Year 2009 NSP 2008 2009/2008 Difference

($49,000) ($216,000) $167,000

The amortization expense details are provided under Tab 2. The major changes from NSP 2008 to Test Year 2009 are summarized as follows:

Amortization Expense ($000’s)

Deferral Account Test Year 2009 NSP 2008 2009/2008 Difference

Property Tax 24 ($2) $26 BCUC Hearing Costs 0 6 (6) Contribution to WEI Taylor 0 28 (28) DC Industrial Deliveries 5 19 (14) Resource Plans 0 0 0 Bill 198 Compliance 9 6 3 BCUC Fees (21) (6) (15) Short Term Interest (7) 11 (18) Long Term Interest (56) 16 (72) Depreciation Adjustment 0 (294) 294 Carbon/Income Tax (3) 0 (3) IFRS 0 0 0

Total ($49) ($216) $167


The above Table shows that amortization expense from NSP 2008 to Test Year 2009 is increasing by a net amount of $167,000. The most significant factor is the completion of the amortization of the depreciation adjustment credit deferral account in 2008. This is offset to some extent by credit deferrals in the short term and long term debt interest rate deferral accounts due to lower interest rates in 2008. The IFRS deferral account is a new deferral account. PNG(N.E.) is seeking approval to record its incremental costs of adopting International Financial Reporting Standards. Commencing with the first quarter in 2011, PNG(N.E.) will be required to show comparative financial information in compliance with IFRS. Changing PNG(N.E.)’s financial statements requires incremental accounting assistance, the cost of which will be recorded in the IFRS deferral account. PNG(N.E.) is delaying commencement of amortization until 2010. The 2010 revenue requirements application will include a proposed amortization period for these costs. PNG(N.E.) is seeking Commission approval of this deferral account as the conversion costs are not expected to be ongoing and given the nature of the project, these costs are difficult to forecast. The PNG-West NSP 2008 settlement agreement contained some commentary on the criteria for setting up new deferral accounts. It was noted that expenditures requiring multi-year amortization and which would not lead to a capital/plant addition, should be set up as a non-rate base deferral account attracting return equivalent to AFUDC. Based on these parameters the IFRS deferral account could be set up as non rate base deferral account attracting AFUDC. Given the fact the accounting work associated with complying with Bill 198 is very similar to the accounting work required to comply with IFRS, PNG(N.E.) is requesting Commission approval to set up the IFRS deferral account as rate base account. The impact on the cost of service is virtually the same as the impact of attracting a return equivalent to AFUDC but it is much easier administratively for PNG(N.E.) to set up the IFRS account consistent with the rate base treatment applied to the Bill 198 compliance deferral account.


OTHER INCOME

Test Year 2009

NSP 2008


$179,000 $171,000 $8,000

The other income forecast, representing penalty fees and connection charges recovered from customers, is based on the historical average over three years. INCOME TAXES

Test Year 2009

NSP 2008


$288,000 $277,000 $11,000

A number of items affect the determination of the income tax expense. The 2008 to 2009 increase in amortization expense and higher return on common equity more than offset the impact of the lower income tax rate in Test Year 2009 compared to under NSP 2008. RETURN ON COMMON EQUITY

Test Year 2009

NSP 2008


Rate of Return on Equity 8.87% 9.02% 0.15% Common Equity Thickness 36% 36% 0 Common Equity (000’s) $12,728 $12,055 $673 Return on Equity (000’s) $1,129 $1,087 $42

The allowed rate of return on equity (“ROE”) is determined each year in November by the Commission’s automatic ROE formula. The reduction in the ROE is offset by higher common equity due to a higher rate base.


CAPITAL STRUCTURE

PNG(N.E.) believes that its common equity component at 36 percent, in combination with its allowed rate of return on common equity at only 40 basis points above the low-risk benchmark utility, significantly under compensates its shareholder and is well below the shareholder compensation for all other comparable utilities in North America. However, given the magnitude of the rate increase projected to be required for the FSJ/DC division for Test Year 2009 and the costs associated with developing the expert evidence to successfully argue its case, PNG(N.E.) is applying to maintain the deemed common equity component of the FSJ/DC division at 36 percent. INTEREST EXPENSE

Test Year 2009

NSP 2008


Short-term debt $100,000 $56,000 $44,000 Long-term debt $1,179,000 $1,493,000 ($315,000)

The Test Year 2009 short term debt interest expense has increased over 2008 due to the increase in the short-term debt component of rate base. The higher short term debt requirement offsets the impact of lower interest rates forecast in 2009. The interest rate on short-term debt is forecast to average 3.65 percent in 2009 versus a forecast of 3.78 percent under NSP 2008. Short term debt is comprised of customer security deposits and operating line draws. The interest rates on both components of short term debt are forecast to be lower in 2009 (see Tab 5, page 2), consistent with the decreases in the forecast prime rate from the October 2008 Econolink consensus forecast. Long-term debt interest expense has decreased compared to the NSP 2008 provision due to lower interest rates. The average embedded cost of long-term debt is expected to decrease by over 150 basis points due mainly to the forecast reduction in interest rates on PNG(N.E.)’s floating rate debt which are consistent with the decreases in the forecast 90-day T-bill rate from the October 2008 Econolink consensus forecast. PNG(N.E.) will continue to record changes in interest expense due to differences between forecast and actual floating rates in its interest rate deferral accounts.


COMPANY USE GAS COST

Test Year 2009

NSP 2008


68 717 GJ 68,603 GJ 114 GJ

$544,000 $510,000 $34,000

The volume of Company use gas forecast for Test Year 2009 is slightly higher than the forecast under NSP 2008. A slightly higher forecast unit cost of gas, implementation of the carbon tax and the higher volume requirement accounts for the overall increase. CAPITAL ADDITIONS IN 2009

Test Year 2009

NSP 2008


Additions including overhead $2,737,000 $2,548,000 $189,000

Less overhead (557,000) (528,000) ($29,000)

Net $2,180,000 $2,020,000 $160,000 The major capital additions planned for 2009 are summarized in the Table below.

Description Budgeted Cost Facility Modifications $172,000 Structure and Grounds Upkeep 177,000 Distribution System 625,000 Mobile/Heavy Equipment 307,000 New Additions 567,000 Customer Growth 188,000

Total $2,036,000 The expenditures shown above are considered necessary to ensure PNG(N.E.) continues to provide its customers with safe, reliable and secure gas delivery service in 2009. These projects account for approximately 93 percent of the total capital expenditures forecast for 2009, excluding overhead. The first four items in the Table are required for sustainment of operations. Information about each of the projects identified above is provided below.


Facility Modifications - $172,000 These are modifications to existing facilities to improve their operational safety and reliability. The activities planned for 2009 include: continuing to add secondary odorant containment and station alarms to certain facilities, a station relocation due to safety and operational concerns, and replacement of a number of obsolete regulators and associated equipment. Structure and Grounds Upkeep - $177,000 A number of smaller projects in 2009 are focused on ensuring continued access and safe operation of pressure reducing facilities and general office buildings. The largest single project is the addition of a meter storage shed at the Fort St. John operations centre at a cost of $31,000. Distribution System - $625,000 The largest project is the continued removal of mechanical couplings on the distribution system. This activity will occur in both Dawson Creek and Fort St. John at a forecast cost of $345,000. The other main activity in this area is the continued replacement of PE 2306 pipe at an estimated cost of $205,000. The replacement of a cathodic protection anode ($24,000) and a number of smaller projects accounts for the remainder of the distribution system capital projects. Mobile/Heavy Equipment - $307,000 The mobile/heavy equipment budget in 2009 includes the scheduled replacement of a plow for installing distribution mains for $143,000, the acquisition of a road boring machine for $76,500 and a replacement of a service truck that has met PNG(N.E.)’s replacement criteria of 7 years or 160,000 kilometres. New Additions - $567,000 The cost of new service additions ($229,000), new mains ($177,000) and new meter sets ($161,000) make up the expenditures for new additions for 2009. Customer Growth - $188,000 Several smaller projects to ensure the operational reliability and adequacy of the system to meet the load demands placed on it are forecast for 2009. The single largest project is the addition of an indirect fired lineheater at an existing pressure reducing facility at a cost of $35,000. In addition a variety of upgrades to smaller stations are also required. This work is required due to increased customer load creating potential pressure regulation issues if left unaddressed.


2009 FORECAST GAS DELIVERIES

The Test Year 2009 forecast of gas deliveries is one of the key components of this Application as the forecast determines the projected amount of revenue PNG(N.E.) will receive from its customers during 2009 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 2009 deliveries to the residential and small commercial customers in each of the Fort St. John and Dawson Creek service areas. Fort St. John Forecast 2009 Deliveries

Fort St. John (GJ’s) Customer

Class Test Year

2009 NSP 2008

Normalized 2008

Normalized 2007

Normalized2006

Residential 1,080,776 1,071,478 1,038,453 1,046,034 1,028,064 Small Commercial 810,006 763,486 779,112 745,926 776,147

Fort St. John Normalized Use per Account (GJ/Customer)

Customer Class

Test Year 2009

Linear Trend 2009

NSP 2008

Projected 2008*

Actual 2007

Residential 118.0 116.7 119.4 115.3 118.7

Small Commercial 539.1 508.9 527.5 531.7 515.2

*Normalized 2008 and Projected 2008 are based on the sum of normalized deliveries to the end of October 2008 plus budgeted deliveries for the November to December 2008 period. The residential customer Test Year 2009 use per account is consistent with recent historical experience. The increase in the small commercial use per account reflects the impact of transportation service customers returning to sales in response to the failure of their gas marketer in mid 2008.


The customer count statistics are provided in the following Table:

Fort St. John Customer Counts

Customer Class

Average for Test Year 2009

Projected Year-end

2008

Projected Weighted

Average 2008

Year-end 2007

Residential 9,158 9,091 9,007 8,962 Small Commercial 1,502 1,492 1,465 1,451

The Test Year 2009 forecast is compared to actual deliveries for 2005 to 2008 in the following table:

Fort St. John (GJ’s) Customer

Class Test Year

2009 Projected

2008* Actual 2007

Actual 2006

Actual 2005

Residential 1,080,776 1,047,926 1,079,971 1,034,382 991,229 Small Commercial 810,006 784,048 776,697 778,088 728,926

*Projected 2008 is the sum of actual deliveries to the end of October 2008 plus budgeted deliveries for the November to December 2008 period.


Dawson Creek Forecast 2009 Deliveries

Dawson Creek (GJ’s)

Customer Class

Test Year 2009

NSP 2008

Normalized2008*

Normalized 2007

Normalized 2006

Residential 633,327 633,493 626,180 606,516 624,363 Small Commercial 494,601 440,968 444,199 431,341 488,487

Dawson Creek

Normalized Use per Account (GJ/Customer)

Customer Class

Test Year 2009

Linear Trend 2009

NSP 2008

Projected 2008*

Actual 2007

Residential 119.0 115.6 120.7 119.2 116.6 Small Commercial 651.4 606.7 599.9 598.2 577.4

*Normalized 2008 and Projected 2008 are based on the sum of normalized deliveries to the end of October 2008 plus budgeted deliveries for the November to December 2008 period. The residential customer Test Year 2009 use per account is consistent with recent historical experience. The increase in the small commercial use per account reflects the impact of transportation service customers returning to sales in response to the failure of their gas marketer in mid 2008. Some Dawson Creek customer count and gas deliveries statistics are provided in the following Tables:

Dawson Creek Customer Counts

Customer Class Average for Test Year 2009

Projected Year-end

2008

Projected Weighted

Average 2008

Year-end 2007

Residential 5,321 5,275 5,252 5,240 Small Commercial 759 751 743 738



Customer Class

Test Year 2009

Projected 2008*

Actual 2007

Actual 2006

Actual 2005

Residential 633,327 615,502 587,797 552,638 533,593

Small Commercial 494,601 434,274 424,726 414,408 401,675

*Projected 2008 is the sum of actual deliveries to the end of October 2008 plus budgeted deliveries for the November to December 2008 period. Other Core Market Customers

The following summarizes the projected 2009 deliveries to the large commercial firm, small industrial sales and transportation service customers for both Fort St. John and Dawson Creek in comparison to information on 2008 deliveries.

Fort St. John (GJ’s)

Customer Class Test Year 2009

NSP 2008

Projected 2008*

Large Commercial Sales 169,700 119,000 121,041 Commercial T-Service 0 72,140 43,654 Small Industrial Sales 135,000 168,000 151,904 Small Industrial T-Service 1,210,800 1,317,000 1,214,334


Customer Class Test Year 2009

NSP 2008

Projected 2008*

Large Commercial 147,700 113,600 129,177 Commercial T-Service 0 67,825 50,971 Small Industrial Sales 70,312 42,210 55,940

*Projected 2008 is the sum of actual deliveries to the end of October 2008 plus budgeted deliveries for the November to December 2008 period. The above forecasts for Test Year 2009 are based on a review of historical deliveries to these customer classes and expected use in 2009 based on discussions with the customers. The large commercial customer increase is due to the return of transportation service customers to sales as a result of the failure of their gas marketer. The small industrial sales increase from 2008 to 2009 in Dawson Creek reflects a new customer coming on stream in mid 2008.


RATE MATTERS Allocation of Revenue Deficiency

PNG(N.E.) has allocated the 2009 revenue deficiency to its customers using the projected 2009 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 average number of customers in the case of the residential and small commercial customers. The annual forecast deliveries to the other customer classes is provided for each of Fort St. John and Dawson Creek service areas. This enables one 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 under 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. RSAM Rate Rider

The Summary of Proposed Rates Effective January 1, 2009 shows a separate line for the 2009 RSAM rate rider which is based on recovering the estimated year-end 2008 RSAM balance in equal amounts over the 2009 to 2011 three year period. The derivation of the 2009 RSAM rate rider is provided in a Table under Tab Rates. The RSAM rider calculation will be updated to reflect the most recent information available when the final 2009 regulatory schedules are filed with the Commission to set rates effective January 1, 2009.


2008/2009 Gas Supply Cost Charge Changes/GCVA Riders The gas supply cost recovery rates indicated in the “Summary of Proposed Rates Effective January 1, 2009” were calculated using PNG’s gas cost flow through model updated to reflect the 2008/2009 gas supply and price arrangements entered into by PNG with its gas suppliers and to reflect the impact of the forecast gas prices contained in a forward gas price strip dated November 24, 2008. PNG(N.E.)’s revenue requirement model is designed to show the recovery of forecast gas supply costs on a flow through basis. In other words, the net margin (i.e. gross revenue less forecast cost of sales) will be the same regardless of what forward gas supply prices are used by PNG(N.E.) to calculate gas supply costs. The gas supply cost rates and GCVA riders shown in the “Summary of Proposed Rates Effective January 1, 2009” are based on the November 24, 2008 forward gas prices. The GCVA riders shown in this Application are projected based on current estimated balances in the respective GCVA deferral accounts at year end 2008. It is anticipated that PNG’s fourth quarter 2008 gas supply cost report to the Commission, to be filed in early December 2008, will contain proposed gas supply cost recovery rates and GCVA rate riders equivalent to those shown under Tab Rates. A Table under Tab Rates entitled “Derivation of Test Year Forecast Gas Supply Cost” shows the derivation of the cost of sales figure shown at line 16 of Schedule 1 under Tab 1. The forecast deliveries by customer class times the indicative gas supply prices by customer class generates the cost of sales figure. Determination of 2009 Unit Company Use Gas Cost Rate The 2009 projected cost of Company use gas is based on the forecast gas prices 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 of Current Rates and January 2009 Rates PNG includes under Tab Rates a comparison of the projected annual gas bills for residential and small commercial customers using current rates and proposed January 1, 2009 rates. The average uses per account reflected in the calculations are the same as the figures used for forecasting gas deliveries to these customer classes in 2009. The bill comparisons for Fort St. John and Dawson Creek service areas are separately discussed below since the delivery rates are different in each service area.

Fort St. John

The average rate increase for residential customers is estimated to be 1.8 percent on the delivery charge component of rates or $6.99 per year for an average customer. If current gas cost recovery rates and GCVA rate riders change effective January 1, 2009 as shown in the rates summary, there will an overall bundled rate decrease of 7.0 percent including the impact of a small reduction in the RSAM rate rider. This assumes a bundled average rate of $10.80/GJ which is $7.32/GJ lower than the electricity equivalent rate of $18.12/GJ assuming a 90 percent gas to electricity efficiency factor and using the trailing block electricity rate applicable under the residential inclining block rate structure. The small commercial customer average rate increase is estimated to be 1.8 percent on the delivery charge component of rates or $23.22 per year for an average customer. If current gas cost recovery rates and GCVA rate riders change effective January 1, 2009 as shown in the rates summary, there will an overall bundled rate decrease of 7.4 percent including the impact of a small reduction in the RSAM rate rider. This assumes a bundled average rate of $9.93/GJ which is $8.56/GJ lower than the electricity equivalent rate of $18.49/GJ assuming a 90 percent gas to electricity efficiency factor. Dawson Creek

The average rate increase for residential customers is estimated to be 1.9 percent on the delivery charge component of rates or $7.04 per year for an average customer. If current gas cost recovery rates and GCVA rate riders change effective January 1, 2009 as shown in the rates summary, there will an overall bundled rate decrease of 7.1 percent including the impact of a small reduction in the RSAM rate rider. This assumes a bundled average rate of $10.60/GJ which is $7.52/GJ lower than the electricity equivalent rate of $18.12/GJ assuming a 90 percent gas to electricity efficiency factor and using the trailing block electricity rate applicable under the residential inclining block rate structure..


The small commercial customer average rate increase is estimated to be 2.3 percent on the delivery charge component of rates. If current gas cost recovery rates and GCVA rate riders change effective January 1, 2009 as shown in the rates summary, there will an overall bundled rate decrease of 7.8 percent including the impact of a small reduction in the RSAM rate rider. This assumes a bundled average rate of $9.37/GJ which is $9.12/GJ lower than the electricity equivalent rate of $18.49/GJ assuming a 90 percent gas to electricity efficiency factor. Demand Side Management Section 4 of the NSP 2008 settlement agreement stated the following with respect to Demand Side Management:

“Resolution PNG(N.E.) will continue to participate in DSM coordination activities and provide a report to the Commission no later than its next revenue requirements application on its efforts in this regard as they pertain to the Fort St. John/Dawson Creek division.”

PNG(N.E.) has not filed a formal report with the Commission regarding its participation in various groups looking at DSM initiatives. The following summarizes the groups that PNG’s Director of Regulatory Affairs and Gas Supply and Manager Community Relations and Administration have been involved with to one degree or another:

• BC Partnership for Energy Conservation and Efficiency

• Industrial Energy Efficiency Working Group

• Working Group on the Built Environment

• Measurement, Analysis and Reporting Task Force

Day to day workloads have not afforded the time to enable PNG to participate fully in the groups noted above. PNG(N.E.) has attempted to keep informed by reviewing meeting materials and participate in meetings by telephone where time permits. PNG(N.E.) is more willing to consider implementing DSM programs as its rates are much more competitive with electricity rates compared to the PNG-West division rates. In other words, the PNG(N.E.) division has some room in its rates to bear the incremental cost of DSM programs to encourage gas conservation. For example, PNG(N.E.) considers that DSM programs that encourage consumers to choose the most efficient natural gas appliances, such as high efficiency furnaces and water heaters, which will also have the fewest greenhouse gas


emissions, may have merit in its service area. However, PNG(N.E.) is concerned that its small customer base of just under 17,000 customers, makes it difficult to justify the cost of implementing any one particular DSM program. PNG(N.E.) encourages the Province to consider administering DSM programs on a province wide basis allowing each utility to opt in and provide the capital needed to support efficient consumer choices. PNG(N.E.) will continue to participate in and/or monitor development of, as appropriate, the Province’s plans for implementation of the Energy Plan policies related to DSM and utility rate structure changes, but submits that additional independent DSM activity is not warranted at this point. Commission Orders Sought by PNG(N.E.)

PNG(N.E.) is seeking the following Commission approvals under this Application:

1. Approval on an interim basis pursuant to section 89 of the Utilities Commission Act and on a permanent basis pursuant to section 58 of the Utilities Commission Act of the delivery charge, Company use and RSAM rates effective January 1, 2009 as set forth in the Table under Tab Rates entitled “Summary of Proposed Rates Effective January 1, 2009”.

2. Approval of a an overhead capitalization rate of 17.81 percent, subject to modification upon filing of the final 2009 revenue requirements application regulatory schedules.

3. Approval of the deferral accounts and amortization expenses for 2009 as set forth in under Tab 2, pages 8 and 9 with specific approval of a deferral account to record PNG(N.E.)’s costs incurred in 2008 and forecast to be incurred in 2009 and beyond to convert to International Financial Reporting Standards in 2011 with amortization to commence subsequent to 2009 based on a future application by PNG.


4. Approval to continue the unaccounted for gas volume deferral account to record the difference between forecast and actual unaccounted for gas (“UAF”) volumes in Test Year 2009 based on using a 1 percent of deliveries UAF loss factor for 2009 and requiring PNG(N.E.) to apply for Commission approval to record actual 2009 UAF losses above 1.5 percent in the deferral account.

All of which is respectfully submitted DATED at Vancouver, British Columbia this 27th day of November 2008. 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. #950 - 1185 West Georgia Street Vancouver, British Columbia V6E 4E6 Telephone: (604) 691-5673 Fax: (604) 697-6210 E-mail: [email protected]

Tab RatesFSJ/DC

2009 Rate App.Page 1

Residential (RS1)

Monthly Fixed Charge $7.00 $7.00 $0.00

Delivery Charge 2.449 0.051 2.500 0.051 Company Use 0.106 0.008 0.114 0.008 GCVA Co. Use Rider (0.102) (0.036) (0.138) (0.036) RSAM 0.103 (0.005) 0.098 (0.005) Interim Rate Refund Rider - - Subtotal Delivery 2.556 0.051 (0.033) 2.574 0.018

Gas Supply Demand 0.053 (0.007) 0.046 (0.007) Gas Supply Commodity 7.937 (0.083) 7.854 (0.083) GCVA Commodity Rider 0.351 (0.738) (0.387) (0.738) Subtotal Commodity 8.341 - (0.828) 7.513 (0.828)

Total 10.897 0.051 (0.861) 10.087 (0.810)

Small Commercial (RS2


Delivery Charge 2.135 0.035 2.170 0.035 Company Use 0.106 0.008 0.114 0.008 GCVA Co. Use Rider (0.102) (0.036) (0.138) (0.036) RSAM 0.103 (0.005) 0.098 (0.005) Interim Rate Refund Rider - - Subtotal Delivery 2.242 0.035 (0.033) 2.244 0.002


Total 10.567 0.035 (0.824) 9.778 (0.789)

Large Commercial (RS3)


Delivery Charge 1.625 0.027 1.652 0.027 Company Use 0.106 0.008 0.114 0.008 GCVA Co. Use Rider (0.102) (0.036) (0.138) (0.036) Interim Rate Refund Rider - - Subtotal Delivery 1.629 0.027 (0.028) 1.628 (0.001)


Total 9.878 0.027 (0.902) 9.003 (0.875)

Proposed Rates January 1, 2009 Rate ChangesCustomer Class

Rates Effective October 1, 2008

2009 Revenue Requirement

2008 / 09 Gas Supply Cost

Change


Summary of Proposed Rates Effective January 1, 2009($/GJ unless otherwise specified)

(Fort St. John Division)

Rate Schedules-09FSJ

Tab RatesFSJ/DC






Change




Commercial Transportation (RS23


Delivery Charge 1.586 - 1.586 - Company Use 0.106 0.008 0.114 0.008 GCVA Co. Use Rider (0.102) (0.036) (0.138) (0.036) Subtotal Delivery 1.590 - (0.028) 1.562 (0.028)

Small Industrial (RS4)


Delivery Charge 0.785 0.020 0.805 0.020 Company Use 0.106 0.008 0.114 0.008 GCVA Co. Use Rider (0.102) (0.036) (0.138) (0.036) Interim Rate Refund Rider - - Subtotal Delivery 0.789 0.020 (0.028) 0.781 (0.008)


Total 8.954 0.020 (0.965) 8.009 (0.945)

Small Industrial Service (RS6)


Delivery Charge 0.9707 0.0188 0.9895 0.0188 Company Use 0.1060 0.0080 0.1140 0.0080 GCVA Co. Use Rider (0.1020) (0.0360) (0.1380) (0.0360) Subtotal Delivery 0.9747 0.0188 (0.028) 0.9655 (0.0092)

Small Industrial Service (RS7

Monthly Fixed Charge $3,000.00 $3,000.00 $0.00


Authorized Overrun 0.4484 0.0091 0.0080 0.4655 0.0171


Tab RatesFSJ/DC






Change






Delivery Charge 0.4946 0.0332 0.5278 0.0332 Company Use 0.1060 0.0080 0.1140 0.0080 GCVA Co. Use Rider (0.1020) (0.0360) (0.1380) (0.0360) Subtotal Delivery 0.4986 0.0332 (0.028) 0.5038 0.0052




Small Industrial Service (RS11Monthly Fixed Charge $3,095.00 $3,095.00 $0.00



Tab RatesFSJ/DC


Residential (RS1)


Delivery Charge 2.251 0.051 2.302 0.051Company Use 0.106 0.008 0.114 0.008GCVA Co. Use Rider (0.102) (0.036) (0.138) (0.036)RSAM 0.103 (0.005) 0.098 (0.005)Interim Rate Refund Rider 0.000 0.000Subtotal Delivery 2.358 0.051 (0.033) 2.376 0.018

Gas Supply Demand 0.053 (0.007) 0.046 (0.007)Gas Supply Commodity 7.937 (0.083) 7.854 (0.083)GCVA Commodity Rider 0.351 (0.738) (0.387) (0.738)Subtotal Commodity 8.341 - (0.828) 7.513 (0.828)

Total 10.699 0.051 (0.861) 9.889 (0.810)

Small Commercial (RS2)


Delivery Charge 1.598 0.035 1.633 0.035Company Use 0.106 0.008 0.114 0.008GCVA Co. Use Rider (0.102) (0.036) (0.138) (0.036)RSAM 0.103 (0.005) 0.098 (0.005)Interim Rate Refund Rider 0.000 0.000Subtotal Delivery 1.705 0.035 (0.033) 1.707 0.002

Gas Supply Demand 0.051 (0.007) 0.044 (0.007)Gas Supply Commodity 7.923 (0.046) 7.877 (0.046) GCVA Commodity Rider 0.351 (0.738) (0.387) (0.738) Subtotal Commodity 8.325 - (0.791) 7.534 (0.791)

Total 10.030 0.035 (0.824) 9.241 (0.789)



Delivery Charge 1.077 0.027 1.104 0.027Company Use 0.106 0.008 0.114 0.008GCVA Co. Use Rider (0.102) (0.036) (0.138) (0.036)Interim Rate Refund Rider 0.000 0.000Subtotal Delivery 1.081 0.027 (0.028) 1.080 (0.001)

Gas Supply Demand 0.052 (0.007) 0.045 (0.007)Gas Supply Commodity 7.846 (0.129) 7.717 (0.129)GCVA Commodity Rider 0.351 (0.738) (0.387) (0.738)Subtotal Commodity 8.249 - (0.874) 7.375 (0.874)

Total 9.330 0.027 (0.902) 8.455 (0.875)





Change

Pacific Northern Gas (N.E.) Ltd.(Dawson Creek Division)


Rate Schedules-09DC

Tab RatesFSJ/DC






Change

Pacific Northern Gas (N.E.) Ltd.(Dawson Creek Division)


Commercial Transportation (RS23


Delivery Charge 1.038 - 1.038 0.000Company Use 0.106 0.008 0.114 0.008GCVA Co. Use Rider (0.102) (0.036) (0.138) (0.036)Subtotal Delivery 1.042 - (0.028) 1.014 (0.028)

Small Industrial (RS4


Delivery Charge 1.053 0.020 1.073 0.020Company Use 0.106 0.008 0.114 0.008GCVA Co. Use Rider (0.102) (0.036) (0.138) (0.036)Subtotal Delivery 1.057 0.020 (0.028) 1.049 (0.008)

Gas Supply Demand 0.022 (0.005) 0.017 (0.005)Gas Supply Commodity 7.792 (0.194) 7.598 (0.194)GCVA Commodity Rider 0.351 (0.738) (0.387) (0.738) Subtotal Commodity 8.165 - (0.937) 7.228 (0.937)

Total 9.222 0.020 (0.965) 8.277 (0.945)

Rate Schedules-09DC

Tab RatesFSJ/DC


Bill ComparisonOctober 2008 to January 2009

FORT ST. JOHN AREA

Annual Bill Annual BillCustomer Classification Estimate Estimate

Annual Use $ $ $ %Residential: 118.0 GJ Monthly Fixed Charge @ 7.00 / mo. 0.712 84.00 0.712 84.00 0.00 Delivery Charge 2.555 301.49 2.614 308.48 6.99 GCVA Co. Use Rider (0.102) (12.04) (0.138) (16.28) (4.25) RSAM Rider 0.103 12.15 0.098 11.56 (0.59)

385.61 387.76 2.15 0.6%

Gas Supply Charge 7.990 942.82 7.900 932.20 (10.62) GCVA Rider 0.351 41.42 (0.387) (45.67) (87.09)

984.24 886.53 (97.71) -9.9%

$11.609 /GJ $1,369.85 $10.799 /GJ $1,274.29 ($95.56) -7.0%Small Commercial: 539.1 GJ Monthly Fixed Charge @ 7.00 / mo. 0.156 84.00 0.156 84.00 0.00 Delivery Charge 2.241 1,208.12 2.284 1,231.34 23.22 GCVA Co. Use Rider (0.102) (54.99) (0.138) (74.40) -19.41 RSAM Rider 0.103 55.53 0.098 52.83 (2.70)

1,292.66 1,293.77 1.11 0.1%

Gas Supply Charge 7.974 4,298.78 7.921 4,270.21 (28.57) GCVA Rider 0.351 189.22 (0.387) (208.63) (397.85)

4,488.01 4,061.58 (426.43) -9.5%

$10.723 /GJ $5,780.67 $9.934 /GJ $5,355.35 ($425.32) -7.4%

Pacific Northern Gas (N.E.) Ltd.(Fort St. John/Dawson Creek Division)

Oct. 1, 2008Proposed Rates

Jan. 1, 2009$ / GJ $ / GJ

Annual BillDifference

Permanent Rates

Billcomparisons-09FSJ Bill Comp

Tab RatesFSJ/DC



DAWSON CREEK AREA


Annual Use $ $ $ %Residential: 119.0 GJ Monthly Fixed Charge @ 7.00 / mo. 0.706 84.00 0.706 84.00 0.00 Delivery Charge 2.357 280.48 2.416 287.53 7.04 GCVA Co. Use Rider (0.102) (12.14) (0.138) (16.42) (4.28) RSAM Rider 0.103 12.26 0.098 11.66 (0.59) Interim Rate Refund Rider 0.000 0.00 0.000 0.00 0.00

364.60 366.77 2.17 0.6%


992.58 894.05 (98.53) -9.9%

$11.405 /GJ $1,357.18 $10.595 /GJ $1,260.82 ($96.36) -7.1%Small Commercial: 651.4 GJ Monthly Fixed Charge @ 7.00 / mo. 0.129 84.00 0.129 84.00 0.00 Delivery Charge 1.704 1,109.99 1.747 1,138.03 28.05 GCVA Co. Use Rider (0.102) (66.44) (0.138) (89.89) (23.45) RSAM Rider 0.103 67.09 0.098 63.84 (3.26)

1,194.64 1,195.98 1.34 0.1%


5,422.91 4,907.65 (515.26) -9.5%

$10.159 /GJ $6,617.54 $9.370 /GJ $6,103.62 ($513.92) -7.8%


$ / GJ

Proposed RatesJan. 1, 2009

$ / GJ


Permanent RatesOct. 1, 2008

Billcomparisons-09DC Bill Comp

Tab RatesFSJ/DC



Average of Fort St. John and Dawson Creek


Annual Use $ $ $ %Residential: 118.5 GJ Monthly Fixed Charge @ 7.00 / mo. 0.709 84.00 0.709 84.00 0.00 Delivery Charge 2.456 291.04 2.515 298.05 7.01 GCVA Co. Use Rider (0.102) (12.09) (0.138) (16.35) (4.27) RSAM Rider 0.103 12.21 0.098 11.61 (0.59)

375.15 377.31 2.16 0.6%


988.41 890.29 (98.12) -9.9%

$11.507 /GJ $1,363.56 $10.697 /GJ $1,267.60 ($95.96) -7.0%Small Commercial: 595.3 GJ Monthly Fixed Charge @ 7.00 / mo. 0.141 84.00 0.141 84.00 0.00 Delivery Charge 1.973 1,174.13 2.016 1,199.76 25.63 GCVA Co. Use Rider (0.102) (60.72) (0.138) (82.14) -21.42 RSAM Rider 0.103 61.31 0.098 58.33 (2.98)

1,258.73 1,259.95 1.22 0.1%


4,955.46 4,484.62 (470.84) -9.5%

$10.440 /GJ $6,214.18 $9.651 /GJ $5,744.57 ($469.61) -7.6%

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.

$ / GJ $ / GJ


Permanent Rates


Oct. 1, 2008Proposed Rates

Jan. 1, 2009

Billcomparisons-09FSJDC Bill Comp

Tab RatesFSJ/DC


2009 2009 Allocation of Rate ChangesTest Year Gross Revenue for Revenue

Customer Classification Gas Deliveries Margin Deficiency Deficiency(GJ) ($) ($) ($/GJ)

Residential (RS1) 1 714 103 5,483,981 87,755 0.051

CommercialSmall Commercial (RS2) 1 304 607 2,858,143 45,736 0.035Large Commercial Firm (RS3) 317 400 532,323 8,518 0.027Commercial Transportation (RS23) 0 0 0 0.000

Small Industrial Sales (RS4) 205 312 262,417 4,199 0.020

Industrial TransportRS6 552 800 648,822 10,383 0.0188RS7 147 000 83,687 1,339 0.0091RS9 70 000 145,166 2,323 0.0332RS10 341 000 364,940 5,840 0.0171RS11 100 000 69,280 1,109 0.0111

TOTAL 4 752 222 10 448 760 167,202


SUMMARY OF GAS DELIVERY CHARGE PROPOSED RATE CHANGESEFFECTIVE JANUARY 1, 2009

Tab RatesFSJ/DC


2009 Test Year Cost of GrossCustomer Classification Gas Deliveries Revenue Gas Margin

(GJ) ($) ($) ($)

Residential (RS1) 1 714 103 19 025 506 13 541 525 5,483,981

CommercialSmall Commercial (RS2) 1 304 607 13 192 125 10 333 982 2,858,143Large Commercial Firm (RS3) 317 400 2 995 878 2 463 554 532,323Commercial Transportation (RS23) 0 0 0 0

Small Industrial Sales (RS4) 205 312 1 825 907 1 563 490 262,417

Industrial TransportRS6 552 800 648 822 0 648,822RS7 147 000 83 687 0 83,687RS9 70 000 145 166 0 145,166RS10 341 000 364 940 0 364,940RS11 100 000 69 280 0 69,280

TOTAL 4 752 222 38 351 311 27 902 552 10 448 760


SUMMARY OF REVENUE, COST OF GAS, GROSS MARGIN

Tab RatesFSJ/DC


Test Year 2009Estimated Test Year Test Year Average Test Year

Customer Count Effective Customer Weighted Average Use Per Account DeliveriesCustomer Classification At Dec. 31st, 2008 Additions Customer Count (GJ) (GJ)

Residential (Rate 1 ) 9,091 67 9,158 118.0 1,080,776

CommercialSmall Commercial Sales (Rate 2) 1,492 10 1,502 539.1 810,006Large Commercial Firm Sales (Rate 3) 169,700Commercial Transportation (RS23) 0

Small Industrial Sales (RS4) 135,000

Industrial TransportationRS6 552,800RS7 147,000RS9 70,000RS10 341,000RS11 100,000

Total 3,406,282

Test Year 2009Test Year Test Year Average Test Year

Customer Count Effective Customer Weighted Average Use Per Account DeliveriesCustomer Classification At Dec. 31st, 2008 Additions Customer Count (GJ) (GJ)

Residential (Rate 1 ) 5,275 46 5,321 119.0 633,327

CommercialSmall Commercial Sales (Rate 2) 751 8 759 651.4 494,601Large Commercial Firm Sales (Rate 3) 147,700Commercial Transportation (RS23) 0


Total 1,345,940


FORT ST. JOHN

DAWSON CREEK

(Fort St. John / Dawson Creek Division)

Derivation of Test Year Forecast Gas Deliveries

Tab RatesFSJ/DC


Test Year 2009Test Year Test Year Average Test Year

Customer Count + Effective Customer = Weighted Average x Use Per Account = DeliveriesCustomer Classification At Dec. 31st, 2008 Additions Customer Count (GJ) (GJ)

Residential (Rate 1 ) 14,366 113 14,479 118.4 1,714,103

CommercialSmall Commercial Sales (Rate 2) 2,243 18 2,261 577.0 1,304,607Large Commercial Firm Sales (Rate 3) 317,400Commercial Transportation (RS23) 0


Industrial Transportation

RS6 552,800RS7 147,000RS9 70,000RS10 341,000RS11 100,000

Total 4,752,222

(Fort St. John/Dawson Creek Division)Summary of Test Year Gas Sales Supporting Schedule


Tab RatesFSJ/DC


2009 Current Weighted TotalFort St. John Test Year Delivery Avg. Delivery Test Year

Deliveries Charge Delivery Customer Current Fixed Charge & Fixed Charge GrossCustomer Classification (GJ) $ / GJ Margin Count Fixed Charge Margin Margin Margin

Residential (Rate 1 ) 1,080,776 2.563 2,770,029 9,158 * 7.00 769,272 3,539,301 3,539,301

CommercialSmall Commercial Sales (Rate 2) 810,006 2.249 1,821,703 1,502 7.00 126,168 1,947,871 1,947,871Large Commercial Sales (Rate 3) 169,700 1.739 295,108 19 150.00 34,200 329,308 329,308Commercial Transport (Rate 23) 0 1.700 0 0 125.00 0 0 0

Small Industrial Sales (Rate 4) 135,000 0.899 121,365 7 410.00 34,440 155,805 155,805

Industrial TransportationRate 6 552,800 1.0847 599,622 10 410.00 49,200 648,822 648,822Rate 7 147,000 0.3244 47,687 1 3,000.00 36,000 83,687 83,687Rate 9 70,000 0.6086 42,602 1 8,547.04 102,564 145,166 145,166Rate 10 341,000 0.3078 104,960 7 3,095.00 259,980 364,940 364,940Rate 11 100,000 0.3214 32,140 1 3,095.00 37,140 69,280 69,280

Total Fort St. John 3,406,282 5,835,216 1,448,964 7,284,181 7,284,181

2009 Current Weighted TotalDawson Creek Test Year Delivery Avg. Delivery Test Year

Deliveries Charge Delivery Customer Current Fixed Charge & Fixed Charge GrossCustomer Classification (GJ) $ / GJ Margin Count Fixed Charge Margin Margin Margin

Residential (Rate 1 ) 633,327 2.365 1,497,818 5,321 7.00 446,964 1,944,782 1,944,782

CommercialSmall Commercial Sales (Rate 2) 494,601 1.712 846,757 759 7.00 63,756 910,513 910,513Large Commercial Sales (Rate 3) 147,700 1.191 175,911 15 150.00 27,000 202,911 202,911Commercial Transport (Rate 23) 0 1.152 0 0 125.00 0 0 0

Small Industrial Sales (Rate 4) 70,312 1.167 82,054 5 410.00 24,600 106,654 106,654

Total Dawson Creek 1,345,940 2,602,540 562,320 3,164,860 3,164,860


Derivation of Test Year Forecast Gross Margin


Tab RatesFSJ/DC





2009 Current Weighted TotalFSJ / DC Combined Test Year Delivery Avg. Delivery Test Year

Gas Sales Charge Delivery Customer Current Fixed Charge & Fixed Charge GrossCustomer Classification (GJ) $ / GJ Margin Count Fixed Charge Margin Margin Margin

Residential (Rate 1 ) 1,714,103 4,267,847 14,479 7.00 1,216,236 5,484,083 5,484,083

CommercialSmall Commercial Sales (Rate 2) 1,304,607 2,668,460 2,261 7.00 189,924 2,858,384 2,858,384Large Commercial Sales (Rate 3) 317,400 471,019 34 150.00 61,200 532,219 532,219Commercial Transport (Rate 23) 0 0 0 125.00 0 0 0

Small Industrial Sales (Rate 4) 205,312 203,419 12 410.00 59,040 262,459 262,459

Industrial Transportation

Rate 6 552,800 0.9787 599,622 10 410.00 49,200 648,822 648,822Rate 7 147,000 0.2184 47,687 1 3,000.00 36,000 83,687 83,687Rate 9 70,000 0.4946 42,602 1 8,547.04 102,564 145,166 145,166Rate 10 341,000 0.1938 104,960 7 3,095.00 259,980 364,940 364,940Rate 11 100,000 0.2074 32,140 1 3,095.00 37,140 69,280 69,280

Total Fort St. John / Dawson Creek 4,752,222 8,437,757 2,011,284 10,449,041 10,449,041

Tab RatesFSJ/DC


2009Fort St. John Test Year Gas Cost Total

Deliveries Charge Gas CostCustomer Classification (GJ) ($ / GJ) ($)

Residential (Rate 1 ) 1,080,776 7.900 8,538,130

CommercialSmall Commercial Sales (Rate 2) 810,006 7.921 6,416,058Large Commercial Sales (Rate 3) 169,700 7.762 1,317,211

Small Industrial Sales (Rate 4) 135,000 7.615 1,028,025

Total Fort St. John 2,195,482 17,299,424

2009Dawson Creek Test Year Gas Cost Total


Residential (Rate 1 ) 633,327 7.900 5,003,283

CommercialSmall Commercial Sales (Rate 2) 494,601 7.921 3,917,735Large Commercial Sales (Rate 3) 147,700 7.762 1,146,447

Small Industrial Sales (Rate 4) 70,312 7.615 535,426

Total Dawson Creek 1,345,940 10,602,891


Derivation of Test Year Forecast Gas Supply Cost


Tab RatesFSJ/DC





2009FSJ / DC Combined Test Year Gas Cost Total


Residential (Rate 1 ) 1,714,103 7.900 13,541,414

CommercialSmall Commercial Sales (Rate 2) 1,304,607 7.921 10,333,792Large Commercial Sales (Rate 3) 317,400 7.762 2,463,659

Small Industrial Sales (Rate 4) 205,312 7.615 1,563,451

Total Fort St. John / Dawson Creek 3,541,422 27,902,315

Customer Classification

Company Company CompanyDemand Commodity Total Use Gas Demand Commodity Total Use Gas Demand Commodity Total Use Gas

($/GJ) ($/GJ) D&C ($/GJ) ($/GJ) ($/GJ) D&C ($/GJ) ($/GJ) ($/GJ) D&C ($/GJ)

Residential (RS1) 0.053 7.937 7.990 0.106 0.046 7.854 7.900 0.114 ( 0.007) ( 0.083) ( 0.090) 0.008

Small Commercial (RS2) 0.051 7.923 7.974 0.106 0.044 7.877 7.921 0.114 ( 0.007) ( 0.046) ( 0.053) 0.008

Large Commercial (RS3) 0.052 7.846 7.898 0.106 0.045 7.717 7.762 0.114 ( 0.007) ( 0.129) ( 0.136) 0.008

Small Industrial (RS4) 0.022 7.792 7.814 0.106 0.017 7.598 7.615 0.114 ( 0.005) ( 0.194) ( 0.199) 0.008

Company Use 0.106 0.114 0.008

Transportation Service 0.106 0.114 0.008

Effective January 1, 2009

Using November 24, 2008 Forward Gas Strip


Gas Supply CostsProposed Rates

Proposed Rates Effective January 1, 2009

Gas Supply CostsRates


Determination of Gas Supply Cost Rate Changes Effective January 1, 2009

Gas Supply Cost Rate ChangesIndicative

FSJ-DC Retail Rate ChangesFSJ-DC-09

Tab RatesFSJ/DC


Allocation of 2008 Annual Unit DemandCustomer Classification Demand Charges Requirements Charge

(GJ) (%) ($) (GJ) ($/GJ)

Residential (RS1) 18 293 50.71% 78,963 1 714 103 0.046

Small Commercial (RS2) 13 342 36.98% 57,592 1 304 607 0.044

Large Commercial (RS3) 3 285 9.10% 14,178 317 400 0.045

Industrial Sales (RS4) 818 2.27% 3,530 205 312 0.017

Company Use Gas 338 0.94% 1,457 68 719 0.021

Total 36 075 100.0% 155,721 3 610 141

Requirement

ALLOCATION OF DEMAND CHARGES EFFECTIVE JANUARY 1, 2009

(Fort St. John/Dawson Creek Division)Pacific Northern Gas (N.E.) Ltd.

Peak Day

FSJ-DC-09FSJ-DC Demand Chrg Allocation

Tab RatesFSJ/DC


Demand Cost $1,457

Commodity Cost $524,477B.C.S.S. Tax $8,163Ice Levy $466Carbon Tax $9,044

$543,607

Total Company use gas requirement 68 719 GJDeliveries 4 752 222 GJ

2009 Unit Company Use Gas Cost Rate$0.114 /GJ $543,607

4 752 222

Commodity Cost of Company Use Gas per GJ Purchased$7.632 /GJ $524,477

68 719



Determination of 2009 Unit Company Use Gas Cost Rate

FSJ-DC-09FSJ-DC Company Use

Tab RatesFSJ/DC


Actual RSAM Balance at Year-end 2007 $702,602 $355,216 $1,057,818

Estimated RSAM Recovery / Deferral in 2008 ($39,090) ($126,746) ($165,836)

Estimated RSAM Balance at Year-end 2008 $663,512 $228,470 $891,982

Years of Amortization 3

RSAM Balance divided by 3 Equals Amortization $297,327

Forecast 2009 Deliveries 1,714,102 1,304,607 3,018,710

One Year of Amortization divided by 2009 Deliveries equals RSAM Rate Rider ($/GJ) 0.098

Small Commercial


Determination of 2009 Revenue Stabilization Adjustment Mechanism (RSAM) Rider

Residential Total

FSJ-DC-09RSAM

Tab RatesFSJ/DC


STATION #2 AECOCDN$/GJ CDN$/GJ

Jan-09 7.5167 7.3667Feb-09 7.4636 7.3936Mar-09 7.2326 7.3526Apr-09 6.9752 7.1356May-09 7.0072 7.1672Jun-09 7.1238 7.2838Jul-09 7.2580 7.4180Aug-09 7.3746 7.5346Sep-09 7.4271 7.5871Oct-09 7.5321 7.6921Nov-09 8.1976 8.0576Dec-09 8.6284 8.4884Average 7.4781 7.5398

November 24, 2008


Forward Gas Price Strip


FSJ-DC-09Forward Gas Strip

Tab 1FSJ/DC


Line Test Year NSPNo. 2009 2008 Source

1 Energy sales (TJ) 3,541 3,352 Tab Rates, page 72 Average rate per GJ $10.50 $10.0534 Transportation service (TJ) 1,211 1,457 Tab Rates, page 75 Average rate per GJ $1.10 $1.0667 Total deliveries (TJ) 4,752 4,809 Tab Rates, page 789 Utility revenue

10 Energy sales $37,039 $33,006 Tab Rates, page 1011 Interim rates - sales 146 680 Tab Rates, page 912 Transportation service 1,312 1,425 Tab Rates, page 1013 Interim rates - transportation 21 121 Tab Rates, page 91415 38,519 35,232 16 Cost of sales 27,903 24,985 Tab Rates, page 10 & 151718 Gross margin 10,616 10,247 1920 Operating expenses 4,139 3,860 Tab 1, page 2, line 621 Maintenance expenses 223 290 Tab 1, page 2, line 1022 Admin. & general expenses 1,370 1,265 Tab 1, page 2, line 1623 Property taxes 977 958 Tab 1, page 6, line 424 Depreciation 1,439 1,349 Tab 2, page 6, line 4925 Amortization (49) (216) Tab 2, page 9, line 2426 Investment income, other revenue (179) (171) Tab 1, page 7, line 72829 7,921 7,3353031 Earned return before income taxes 2,695 2,912 32 Income taxes 288 276 Tab 3, page 1, line 143334 Earned return $2,407 $2,6373536 Utility rate base $35,346 $33,486 Tab 2, page 1, line 213738 Return on rate base 6.81% 6.99% Tab 5, page 1, line 23


UTILITY INCOME & RETURN

SCHEDULE 1(000's)

Tab 1FSJ/DC



SUMMARY OF OPERATING, MAINTENANCE& ADMINISTRATIVE & GENERAL EXPENSES

(000's)

Line Test Year NSPNo. Account and Description 2009 2008

1 OPERATING EXPENSES2 - wages $1,492 $1,3783 - gas 544 510 4 - transferred to capital (208) (200) 5 - other 2,312 2,173

6 Total Operating 4,139 3,860

7 MAINTENANCE EXPENSES8 - wages 71 108 9 - other 152 182

10 Total Maintenance 223 290

11 ADMINISTRATIVE AND GENERAL EXPENSES12 - wages - - 13 - benefits 463 474 14 - transferred to capital (216) (205) 15 - other 1,124 996

16 Total Admin & General 1,370 1,265

17 TOTAL EXPENSES $5,732 $5,415

Tab 1FSJ/DC



OPERATING EXPENSES

(000's)


1 664 Communications $9 $132 665 Pipelines 83 93 3 Pipelines - Gas 544 510 4 667 Regulating stations 111 108 5 Regulating stations - Gas - -

6 Total transmission 746 724

7 670 Supervision 441 361 10 673 Removing & resetting meters 235 249 11 674 Service on customer premises 37 32 12 675 Mains and services 311 290 13 677 Regulating stations 15 17 14 679 Other - -

15 Total distribution 1,039 949

16 684 Communications 1 1 17 685 General systems operations 190 246

Shared Services from Parent 449 405 18 688 Other general operations 530 470 18 689 Transferred to capital (208) (200)

19 Total general 961 922

20 700 Sales supervision 13 13 21 701 Advertising 5 - 22 702 Demonstration and selling 2 1 23 709 Other 2 2

24 Total sales 22 16

25 711 Customer contracts 1 11 Shared Services from Parent 152 141

26 712 Meter reading 187 175 27 713 Customer billing 448 367

Shared Services from Parent 330 299 28 714 Credit and collections 18 18

Shared Services from Parent 76 82 29 718 Uncollectible accounts 159 156

30 Total customer accounting 1,370 1,248

31 Total operating $4,139 $3,860

Tab 1FSJ/DC



MAINTENANCE EXPENSES

(000's)


1 864 Communications $0 $12 865 Pipe lines 22 40 3 866 Compressors - - 4 867 Regulating stations 39 67


6 872 Structures 3 2 7 875 Mains and services 102 102 8 877 Regulating stations 10 14 9 878 Meters 47 56

10 879 Other - -

11 Total distribution 162 174

12 884 Communications - 3 13 885 General - 5

14 Total general - 8

15 Total maintenance $223 $290

Tab 1FSJ/DC



ADMINISTRATIVE AND GENERAL EXPENSES

(000's)


1 721 Administration $2 $42 Shared Services from Parent 751 664

3 722 Audit, legal & consulting fees 81 58

4 723 Insurance 142 136

5 724 Reserve for damages - -

6 725 Employee benefits 463 474

7 728 Shared Services from Parent 106 93 8 Regulation 37 36 9 Donations 5 5

10 Other - -

11 729 Transferred to capital (216) (205)

12 Total general and administrative $1,370 $1,265

Tab 1FSJ/DC



TAXES OTHER THAN INCOME TAXES

(000's)


1 PROPERTY TAXES2 Regular $755 $6983 1% in lieu 223 260

4 TOTAL $977 $958

Tab 1FSJ/DC



MISCELLANEOUS OPERATING REVENUE

(000's)

Line Test Year NSPNo. Description 2009 2008

1 Penalty charges $117 $110

2 Connection Fees 24 25

3 Rents - -

4 Overheads recovered 28 23

5 Automotive surcharges 4 6

6 Other 5 7

7 $179 $171

Tab 2FSJ/DC



1 Plant in service beginning of year $64,761 $61,263 Tab 2, page 3, line 462 Additions 2,737 2,548 Tab 2, page 3, line 463 Disposals (44) (127) Tab 2, page 3, line 4645 Plant in service end of year 67,454 63,685 6 Accumulated depreciation 26,302 24,378 Tab 2, page 6, line 4378 Net plant in service end of year 41,153 39,306 9

10 Net plant beginning of year 40,198 38,462 Tab 2, pages 3 & 6, lines 46 & 431112 Net plant in service midyear 40,675 38,88414 Contributions for construction (7,057) (7,010) Tab 2, page 16, line 1315 Unamortized deferred charges 431 520 Tab 2, page 9, line 1316 Deferred income taxes (553) (553)17 Reserve for damages (69) (69)18 Cash working capital 1,709 1,534 Tab 2, page 10, line 819 Other working capital 210 181 Tab 2, page 15, line 152021 Utility rate base, midyear $35,346 $33,486


UTILITY RATE BASE

SCHEDULE 2(000's)


Tab 2FSJ/DC


Fort St. John / Dawson Creek Division

GAS PLANT IN SERVICE - 2008

($ 000's)Forecast

Actual 2007 Ending

Line Description BalanceAdditions (incl O/H) Allocations Transfers Retirements Balance

1 Transmission plant2 460 Land 11 113 461 Land rights 81 814 462 Compressor structures 465 4655 463 Regulating structures 146 1466 465 Mains 6,138 6,1387 466 Compressor equipment8 467 Regulating equipment 3,237 341 45 3,6229 468 Communications 130 130

10 469 Other 18 18

11 10,226 341 45 10,61212 Distribution plant13 470 Land 37 3714 471 Land rights 222 22215 472 Structures 1,165 172 43 1,38016 473 Services 14,668 398 62 15,12817 474 House installations 4,394 39 11 4,44418 475 Mains 21,585 1,520 299 23,40319 476 Compressor equipment20 477 Regulating equipment 1,379 109 21 (1) 1,50921 478 Meters 1,891 90 17 1,99822 479 Other 20 20

23 45,361 2,329 452 (1) 48,14224 General plant25 480 Land 77 7726 481 Land rights 1 127 482 Structures 1,196 1,19628 483 Office equipment 275 10 28629 484 Transportation equipment 1,056 255 36 1,34830 485 Heavy work equipment 736 73631 486 Tools 1,063 46 1,10932 487Computer equipment 974 (14) 96033 488 Communications 299 29938 489 Other (4) (4)

39 5,674 312 36 (14) 6,00840 Construction overheads41 Unallocated construction costs 43 (43)42 System operations transfers 186 (186)43 Administrative transfers 189 (189)44 Depreciation 79 (79)

45 497 (497)

46 61,261 3,478 36 (15) 64,761

Forecast

Tab 2FSJ/DC


GAS PLANT IN SERVICE - TEST YEAR 2009

($ 000's)Forecast

Forecast Ending

Line Description Balance Additions Allocations Retirements Balance

1 Transmission plant2 460 Land 11 11 3 461 Land rights 81 81 4 462 Compressor structures 465 465 5 463 Regulating structures 146 146 6 465 Mains 6,138 6,138 7 466 Compressor equipment - 8 467 Regulating equipment 3,622 260 84 3,966 9 468 Communications 130 130 10 469 Other 18 18

11 10,612 260 84 10,955 12 Distribution plant13 470 Land 37 37 14 471 Land rights 222 222 15 472 Structures 1,380 181 63 1,623 16 473 Services 15,128 276 83 15,487 17 474 House installations 4,444 92 33 4,569 18 475 Mains 23,403 802 266 24,471 19 476 Compressor equipment 0 0 20 477 Regulating equipment 1,509 71 29 1,609 21 478 Meters 1,998 99 2,097 22 479 Other 20 20

23 48,142 1,521 473 50,136 24 General plant25 480 Land 77 77 26 481 Land rights 1 1 27 482 Structures 1,196 1,196 28 483 Office equipment 286 5 291 29 484 Transportation equipment 1,348 88 (44) 1,392 30 485 Heavy work equipment 736 219 955 31 486 Tools 1,109 77 1,186 32 487 Computer equipment 960 960 33 488 Communications 299 11 309 38 489 Other (4) (4)

39 6,008 399 (44) 6,363 40 Construction overheads41 Unallocated construction costs 45 (45) 42 System operations transfers 208 (208) 43 Administrative transfers 216 (216) 44 Depreciation 88 (88)

45 557 (557)

46 64,761 2,737 (44) 67,454

(Fort St. John/Dawson Creek Division)Pacific Northern Gas (N.E.) Ltd.

Forecast

Tab 2FSJ/DC


Test Year Forecast

Line Description 2009 2008

1 Balance, Beginning of Year 64,761 61,261

2 CIAC Balance, Beginning of Year (11,601) (11,423)

3Plant Cost, net of CIAC, Beginning of Year 53,160 49,838

4 Additions during year:5 Plant Cost 2,180 2,9496 Allocation of overheads 557 530

7 Total Plant Additions 2,737 3,478

8 Contributions in Aid of Construction (178) (178)9 Total Additions 2,559 3,300

10 Plant Retirements:11 Normal Course (44) 2212 Deactivated Assets -

13 CIAC Retirements - -

14 Total Retirements (44) 22

15 Balance, End of Year 55,675 53,160

16 Closing balance consists of:

17 Plant Cost 67,454 64,761

18 CIAC (11,779) (11,601)


Pacific Northern Gas (NE) Ltd.Fort St. John / Dawson Creek

GAS PLANT IN SERVICE - CONTINUITY OF PLANT COST

(000's)

Tab 2FSJ/DC


Line Description RateActual 2007

Balance Provision Transfers Retirements RecoveriesDepreciation Adjustment

Forecast '08 Ending Balance

1 Gathering Plant2 Franchises & Consents 1.00% () ()3 Gas Holders - Manufacturing 1.00% (9) (9)4 Gas Holders - Storage (4) (4)56 (13) (13)7 Transmission plant8 461 Land rights 3.59% (50) (3) (53)9 462 Compressor structures 3.00% (129) (14) (143)

10 463 Regulating structures 3.00% (35) (4) (39)11 465 Mains 2.78% (3,262) (171) (3,433)12 466 Compressor equipment N/A13 467 Regulating equipment 3.43% (1,310) (111) (1,421)14 468 Communications 5.00% (85) (6) (92)15 469 Other 3.00% (3) (1) (3)1617 (4,874) (310) (5,184)18 Distribution plant19 471 Land Rights 0.72% (17) (2) (19)20 472 Structures 3.00% (234) (35) (269)21 473 Services 2.04% (3,359) (299) (3,657)22 474 House installations 2.87% (1,627) (126) (1,753)23 475 Mains 2.44% (8,278) (526) (8,804)24 476 Compressor equipment 0.00% () () ()25 477 Regulating equipment 3.10% (798) (43) 1 (840)26 478 Meters 3.00% (491) (57) (548)27 479 Other 3.00% (5) (1) (6)2829 (14,810) (1,088) 1 (15,897)3031 General plant32 481 Land Rights () () ()33 482 Structures 3.00% (593) (36) (629)34 483 Office equipment 1.17% (234) (3) (237)35 484 Transportation equipment 12.79% (701) (135) (36) (873)36 485 Heavy work equipment 4.99% (240) (37) (277)37 486 Tools 4.53% (502) (48) (550)38 487 Computer equipment 3.15% (692) (31) 14 (709)39 488 Communications 4.59% (184) (14) (197)40 489 Other 3.00% 3 341 (3,144) (303) (36) 14 (3,470)4243 (22,841) (1,701) (36) 15 (24,564)44

45 Amortization of CIAC 2554647 Depreciation capitalized 844849 Net Depreciation Expense (1,363)

Fort St. John / Dawson Creek Division

CONTINUITY OFACCUMULATED DEPRECIATION

Forecast

FOR THE YEAR 2008

($ 000's)

Tab 2FSJ/DC


Line Description Rate Balance Provision Retirements Recoveries


1 Gathering Plant2 Franchises & Consents 1.00% () ()3 Gas Holders - Manufacturing 1.00% (9) (9)4 Gas Holders - Storage (4) (4)56 (13) (13)7 Transmission plant8 461 Land rights 3.59% (53) (3) (56)9 462 Compressor structures 3.00% (143) (14) (157)10 463 Regulating structures 3.00% (39) (4) (44)11 465 Mains 2.69% (3,433) (165) (3,598)12 466 Compressor equipment N/A13 467 Regulating equipment 3.44% (1,421) (125) (1,545)14 468 Communications 3.36% (92) (4) (96)15 469 Other 3.00% (3) (1) (4)1617 (5,184) (316) (5,500)18 Distribution plant19 471 Land Rights 0.72% (19) (2) (20)20 472 Structures 2.99% (269) (41) (310)21 473 Services 2.04% (3,657) (308) (3,965)22 474 House installations 2.82% (1,753) (125) (1,879)23 475 Mains 2.32% (8,804) (544) (9,348)24 476 Compressor equipment 3.00% () () ()25 477 Regulating equipment 2.92% (840) (44) (885)26 478 Meters 3.00% (548) (60) (608)27 479 Other 3.00% (6) (1) (6)2829 (15,897) (1,125) (17,022)3031 General plant32 481 Land Rights () () ()33 482 Structures 2.94% (629) (35) (664)34 483 Office equipment 1.29% (237) (4) (241)35 484 Transportation equipment 12.80% (873) (173) 44 (9) (1,010)36 485 Heavy work equipment 4.61% (277) (34) (311)37 486 Tools 4.27% (550) (47) (597)38 487 Computer equipment 2.93% (709) (28) (738)39 488 Communications 4.02% (197) (12) (209)40 489 Other 3.00% 3 341 (3,470) (333) 44 (9) (3,767)4243 (24,564) (1,773) 44 (9) (26,302)4445 Amortization of CIAC 24,539 2464647 Depreciation capitalized 884849 Net Depreciation Expense (1,439)

ACCUMULATED DEPRECIATION

TEST YEAR 2009

($ 000's)


CONTINUITY OF

Forecast

Tab 2FSJ/DC


Test Year ForecastLine Description 2009 2008

1 Balance, Beginning of Year (24,564) (22,841)

2CIAC Accumulated Balance, Beginning of Year 4,510 4,255

3Utility Accumulated Depreciation, Beginning of Year (20,054) (18,585)

4 Depreciation Provision:5 Plant (1,773) (1,701)

6 Contributions in Aid of Construction 246 255

7 Depreciation Adjustment Deferral

8 Total Additions (1,527) (1,447)

9 Plant Retirements:10 Normal Course 44 (22)11 Deactivated Assets

12 CIAC Retirements

13 Removal Costs

14 Proceeds on Disposals (9)

15 Total Retirements 35 (22)

16 Balance, End of Year (21,546) (20,054)

17 Closing Balance Consists of:

18 Accumulated Depreciation - Plant (26,302) (24,564)

19 Accumulated Amortization - CIAC 4,756 4,510

20 Balance, End of Year (21,546) (20,054)

Fort St. John / Dawson CreekPacific Northern Gas (NE) Ltd.

(000's)

GAS PLANT IN SERVICE - CONTINUITY OF ACCUMULATED DEPRECIATION

Tab 2FSJ/DC



CONTINUITY OF DEFERRED CHARGES

YEAR 2008(000's)

ActualLine Description Balance '07 Additions Tax Amortization Balance '08

1 Rate base items2 Property tax variance (2) 35 (11) (2) 243 BCUC Hearing costs (3) 3 (1) 7 (8)4 Contribution to WEI Taylor 28 0 0 28 05 Studies 0 0 0 0 06 RSAM 590 (166) 51 0 4767 DC Industrial Deliveries 18 9 (3) 19 58 Resource Plans (0) 20 (6) 0 149 Bill 198 Compliance Costs 13 15 (5) 6 18

10 IFRS 0 5 (2) 0 311 644 (80) 25 57 5321213 Average rate base for the year $5881415 Interest bearing deferrals16 BCUC Fees (6) (31) 10 (6) (22) 17 Short Term Interest Rate deferral (26) (8) 2 11 (43) 18 Long Term Interest Rate deferral 33 (187) 57 16 (113) 19 Depreciation Adjustment (285) (9) - (294) (0) 20 Carbon / Income Tax - (4) 1 - (3) 21 GCVA (554) (277) 84 0 (748) 2223 (839) (516) 153 (273) (929) 2425 Total deferrals (excl. debt issue) ($195) ($596) $178 ($216) ($397)262728 Debt Issue Costs 529 0 0 96 $433


Tab 2FSJ/DC




TEST YEAR 2009(000's)

ForecastLine Description Balance '08 Additions Tax Amortization Balance '09

1 Rate base items2 Property tax variance 24 0 0 24 03 BCUC Hearing costs (8) 12 (4) 0 04 Contribution to WEI Taylor 0 0 0 0 05 Studies 0 0 0 0 06 RSAM 476 (296) 89 0 2697 DC Industrial Deliveries 5 0 0 5 08 Resource Plans 14 0 0 0 149 Bill 198 Compliance Costs 18 0 0 9 9

10 IFRS 3 49 (15) 0 3811 532 (235) 70 38 329 1213 Average rate base for the year $4311415 Interest bearing deferrals16 BCUC Fees (22) (1) 0 (22) (1) 17 Short Term Interest Rate deferral (43) 19 (6) (7) (24) 18 Long Term Interest Rate deferral (113) (5) 0 (57) (61) 19 Depreciation Adjustment (0) - 0 - (0) 20 Carbon / Income Tax (3) - 0 (3) 0 21 GCVA (748) 2,389 (717) 0 924 2223 (929) 2,402 (723) (88) 839 2425 Total deferrals (excl. debt issue) ($397) $2,168 ($652) ($49) $1,168262728 Debt Issue Costs $433 $0 $0 $85 $348


Tab 2FSJ/DC



CASH WORKING CAPITAL

FOR THE YEAR ENDED DECEMBER 31, 2009($000's)

Line Lag /(Lead) WorkingNo. Description Days Expense Capital

1 Revenue 58.3

2 Expense (39.8)

3 Operating working capital 18.6 35,587 $1,809

4 Adjustments:

5 Budget Billing Plan ($228)

6 PST, ICEF Levy & Carbon Tax $24

7 Goods and Services Tax $104

8 Cash working capital $1,709


Tab 2FSJ/DC



REVENUE LAG DAYS


RevenueLine Lag ExtendedNo. Revenues Days Revenue Revenue

1 Residential - monthly 47.4 $6,083 $288,2102 - bimonthly 63.7 12,942 824,830 34 Small commercial - monthly 60.1 1,777 106,747 5 - bimonthly 63.6 11,415 726,250 67 Large commercial - firm 45.9 2,996 137,515 89 Small industrial 48.0 2,893 138,895

1011 Revenue Deficiency 58.3 167 9,752 1213 Other operating revenue 58.3 179 10,415 1415 Average revenue lag days 58.3 $38,452 $2,242,612


Tab 2FSJ/DC



EXPENSE LEAD DAYS


ExpenseLine (Lead) Normalized ExtendedNo. Expenses Days Expenses Expenses

1 Gas purchases-baseload (40.2) $264 ($10,598)

2 Gas purchases-seasonal (40.2) 28,183 (1,132,937)

3 Operating payrolls (5.0) 1,562 (7,812)

4 Employee benefits (20.9) 463 (9,669)

5 Uncollectible accounts (59.3) 159 (9,443)

6 Other operating expenses (31.4) 3,286 (103,186)

7 Expenses credited/capitalized (10.6) (425) 4,480

8 Insurance 182.5 142 25,955

9 Property taxes (1.0) 977 (977)

10 Franchise Fees (242.5) 687 (166,709)

11 Income taxes payable (15.2) 288 (4,375)

12 Average expense lag days (39.8) $35,587 ($1,415,272)


Tab 2FSJ/DC



CASH WORKING CAPITAL - GOODS AND SERVICES TAX


Line Taxable GST Receipt Payment Net WorkingNo. Description Amount @ 5% Lag Days (Lead) Days Lag/(Lead) Capital

1 Revenues2 Residential and commercial $35,356 $1,768 19.5 (30.4) (10.9) (52.6)3 Industrial - FSJ 2,519 126 31.0 (46.5) (15.5) (5.3)4 Industrial - DC 644 32 39.0 (60.8) (21.8) (1.9)5 Franchise fee 687 34 20.5 (31.9) (11.4) (1.1)6 Carbon Tax 2,124 106 20.4 (30.7) (10.4) (3.0)78 $41,330 $2,067 (11.3) ($63.9)91011 Recovery Payment Net Working12 Lag Days (Lead) Days Lag/(Lead) Capital13 Purchases14 Capital expenditures $2,180 $109 30.4 8.2 38.6 11.515 Gas supply 28,446 $1,422 60.8 (25.0) 35.8 139.516 Operating costs 3,286 $164 30.4 8.2 38.6 17.41718 $33,912 $1,696 36.3 $168.41920 $104.5


Tab 2FSJ/DC



CASH WORKING CAPITAL - PROVINCIAL SALES TAX & ICEF LEVY


Line Taxable P.S.T. Receipt Payment Net WorkingNo. Description Amount @ 7% Lag Days (Lead) Days Lag/(Lead) Capital

1 Revenues2 Commercial sales $16,244 $1,137 21.6 (23.0) (1.4) (4.2)3 Industrial sales - FSJ 1,187 83 33.2 (23.0) 10.2 2.34 Industrial sales - DC 644 45 39.0 (53.4) (14.4) (1.8)5 Franchise fees 323 23 23.0 (24.1) (1.1) (0.1)6 PST Subtotal 18,397 1,288 (3.7)78 ICEF Levy9 @ 0.4%

10 Residential sales $19,118 $76 17.8 (23.0) (5.2) (1.1)11 Commercial sales 16,244 65 21.6 (23.0) (1.4) (0.2)12 Industrial sales - FSJ 1,187 5 33.2 (23.0) 10.2 0.113 Industrial sales - DC 644 3 39.0 (53.4) (14.4) (0.1)14 Franchise fees 666 3 20.3 (23.5) (3.2) (0.0)15 ICEF Levy Subtotal 37,858 151 (1.3)1617 Taxable Carbon18 Gas sales subject to Carbon Tax GJs Tax19 Residential sales - January to June 981 040 $487 17.8 (15.0) 2.8 3.720 - July to December 733 063 546 17.8 (15.0) 2.8 4.121 Commercial sales - January to June 901 976 448 21.6 (15.0) 6.6 8.122 - July to December 720 031 536 21.6 (15.0) 6.6 9.723 FSJ Small Industrial sales - January to June 70 592 35 33.2 (15.0) 18.2 1.824 - July to December 64 408 48 33.2 (15.0) 18.2 2.425 DC Small Industrial sales - January to June 36 260 18 39.0 (45.4) (6.4) (0.3)26 - July to December 7 852 6 39.0 (45.4) (6.4) (0.1)27 Carbon Tax Subtotal 3515 222 2,124 20.4 (15.3) 29.42829 PST, ICEF Levy & Carbon Tax Total $24.3


Tab 2FSJ/DC



OTHER WORKING CAPITAL ITEMS


Line Transmission MaterialsNo. Description Line Pack & Supplies Total

1 MONTH END BALANCES

2 January 0 $198 $198

3 February 0 206 206

4 March 0 204 204

5 April 0 203 203

6 May 0 191 191

7 June 0 212 212

8 July 0 227 227

9 August 0 219 219

10 September 0 223 223

11 October 0 223 223

12 November 0 197 197

13 December 0 220 220

14 Total $0 $2,525 $2,525

15 Average balance $0 $210 $210


Tab 3FSJ/DC



1 Calculation of Taxable Income2 Earned return before income taxes $2,695 $2,912 Tab 1, page 1, line 313 Interest (1,279) (1,549) Tab 5, page 1, lines 1, 3, 6 & 84 Permanent differences 13 85 Timing differences (470) (495) Tab 3, page 1, line 2667 Taxable income $960 $87589 Calculation of Income Tax Expense

10 Income taxes payable $288 $27611 Part I.3 tax 0 012 Deferred income tax 0 01314 Income tax expense $288 $2761516 Particulars of Timing Differences17 A. Tax Effects Subject To Flowthrough18 Depreciation $1,439 $1,349 Tab 1, page 1, line 2419 Amortization (49) (216) Tab 1, page 1, line 2520 Capital cost allowance (1,520) (1,302)21 Deferred charges 0 022 Overheads capitalized (340) (326)23 Other 0 0242526 Timing differences ($470) ($495)2728 Tax rate 30.00% 31.50%29 Surtax Rate 0.00% 0.00%30 Deferred tax rate 30.00% 31.50%

(000's)


INCOME TAXES

SCHEDULE 3

Tab 4FSJ/DC



1 Opening balance2 Share capital $8,295 $8,2953 Contributed surplus 0 04 Retained earnings 4,122 3,80256 12,417 12,09778 Net income 1,129 1,0889 Shares issued 0 0

10 Preferred dividends 0 011 Common dividends (513) (1,172)1213 Closing balance $13,032 $12,013141516 Midyear common equity $12,725 $12,055


(000's)


COMMON EQUITY

SCHEDULE 4

Tab 5FSJ/DC



1 Short term borrowings $2,738 $1,4802 proportion 7.75% 4.42%3 rate of return 3.65% 3.78% Tab 5, page 2, line 114 return component 0.28% 0.17%56 Long term debt $19,883 $19,951 Tab 5, page 3, line 557 proportion 56.25% 59.58%8 rate of return 5.93% 7.49% Tab 5, page 3, line 579 return component 3.34% 4.46%

1011 Preferred shares $0 $012 proportion 0.00% 0.00%13 rate of return 6.48% 6.48%14 return component 0.00% 0.00%1511 Common equity $12,725 $12,05512 proportion 36.00% 36.00%13 rate of return 8.87% 9.02%14 return component 3.19% 3.25%1516 Total capitalization $35,346 $33,4861718 Return on rate base 6.81% 7.87%1920 Utility rate base $35,346 $33,486 Tab 2, page 1, line 21

(000's)


RETURN ON CAPITAL

SCHEDULE 5

Tab 5FSJ/DC



SHORT TERM DEBT

FOR THE YEAR ENDED DECEMBER 31(000's)

Test Year NSP2009 2008

1 Customer Security Deposits2 Average annual balance $1,066 $1,0663 Interest rate applicable to deposits 1.19% 2.88%4 Annual Interest Expense $13 $3156 Operating Line / Other7 Average annual draw $1,673 $4148 Interest rate 5.22% 6.09%9 Annual Interest Expense $87 $25

1011 Average short term interest rate 3.65% 3.78%

Tab 5FSJ/DC



LONG TERM DEBT



1 Secured Debentures Series 20182 Liability beginning of year $1,592 $1,6603 Sinking fund payments (68) (68) 4 Average Capitalization 1,583 1,651 5 Annual Interest Expense 139 145 6 Issue costs beginning of year (8) (9) 7 Amortization of Issue Costs 1 2 89 Effective Cost Rate 8.89% 8.89%

1011 Roynat 2017 Loan12 Liability beginning of year $11,000 $11,00013 Sinking fund payments - - 14 Average Capitalization 11,000 11,000 15 Annual Interest Expense 624 801 16 Issue costs beginning of year 359 433 17 Amortization of Issue Costs 65 74 1819 Effective Cost Rate 6.28% 8.00%2021 2007 5-year Term Intercompany Loan22 Liability beginning of year $7,300 $7,30023 Issue during the year - - 24 Sinking fund payments - - 25 Average Capitalization 7,300 7,300 26 Annual Interest Expense 327 444 27 Issue costs beginning of year 66 87 28 Amortization of Issue Costs 19 21 2930 Effective Cost Rate 4.75% 6.39%3132 Total Actual Debt33 Total Average Capitalization 19,883 19,951 3435 Effective Cost Rate 5.93% 7.49%



2009 Revenue Requirements Application

to the


November 27, 2008




November 27, 2008

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

Tab Application Tumbler Ridge 2009 Rate App. Page 1

IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996,

c. 473, as amended

- and -

In The Matter Of




November 27, 2008 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 Tumbler Ridge Division in accordance with this Application, effective January 1, 2009. 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. The following narrative provides the submissions by PNG(N.E.) in support of the applied for rates effective January 1, 2009.


INTRODUCTION PNG(N.E.)’s 2009 revenue requirements Application sets out PNG(N.E.)’s budgeted 2009 costs and forecast revenues using currently approved rates and forecast 2009 gas deliveries. The extent to which forecast revenues vary from forecast costs determines whether PNG(N.E.) is seeking Commission approval of rate increases or decreases for the Tumbler Ridge division. PNG(N.E.) compares its forecast 2009 costs to the Commission approved negotiated settlement of PNG(N.E.)’s 2008 revenue requirements application (“NSP 2008”) to put the 2009 figures in context. The forecast 2009 calendar year figures are identified in this Application under the heading “Test Year 2009”. The following regulatory financial schedules are included under Tabs 1 to 5 of this Application:

• Tab 1 - Utility Income & Return

• Tab 2 - Utility Rate Base

• Tab 3 - Income Taxes

• Tab 4 - Common Equity

• Tab 5 - Return on Capital The regulatory schedules compare Test Year 2009 figures to NSP 2008 figures. A Table is provided on the next page comparing the Test Year 2009 cost of service described in this Application to the NSP 2008 cost of service approved by the Commission. A higher Test Year 2009 cost of service compared to NSP 2008 and higher forecast gas deliveries in 2009 with corresponding higher revenues results in a net projected revenue deficiency in 2009. Consequently, PNG(N.E.) is applying for Commission approval to increase its rates effective January 1, 2009.


Test Year NSPEXPENSES 2009 2008 Total Subtotal

OperatingLabour 233 226 7Other 320 333 (13)Sub-total 553 558 (6)

MaintenanceLabour 25 24 1Other 69 39 29Sub-total 94 63 30

Administrative and GeneralLabour 0 0 0Total Company Benefits 49 49 1Other 85 76 9Sub-total 135 125 9

Total (O, M, A & G) Excluding Co. Use 781 747 34 34

Transfers to Capital Operating (4) (6) 2

Transfers to Capital Admin. & Gen. (4) (6) 2

Property Taxes 79 79 0

Depreciation 119 107 12

Amortization (39) (87) 48

Other Income (10) (12) 2 66

Total Expenses Excluding Co, Use 921 822 100 100

Income Taxes 12 (9) 20

Return on Common Equity 54 49 5

Short Term Debt 12 7 5

Long Term Debt 59 64 (5) 25

Total Cost of Service Excluding Co. Use 1058 933 125 125

Company Use Gas 107 94

Total Cost of Service Including Co. Use 1165 1027

2008 to 2009 Cost of Service Increase (Decrease) 125

2008 to 2009 Margin Decrease (Increase) (58)

2009 Revenue Deficiency (Sufficiency) 67

Difference

Test Year 2009 vs. NSP 2008COST OF SERVICE COMPARISON

($000)


The major components of the Test Year 2009 cost of service are summarized below in comparison to the corresponding NSP 2008 figures. The Table shows the main drivers of the projected revenue deficiency in 2009.

$000’s Cost of Service Item Test Year

2009 NSP 2008


Operating, Maintenance, Administrative and General Expenses $781 $747 $34

Transfers to Capital, Operating, Administrative and General (8) (12) 4

Other Cost of Service items including property taxes and depreciation 149 87 62

Return components including return on equity, income taxes and debt costs 136 111 25

Cost of Service Ex. Co. Use Gas Cost $1,058 $933 $125

Margin Using 2008 Rates $991 $933 ($58)

Total Test Year 2009 Revenue Deficiency $67

Total Cost of Service Ex. Co. Use Gas $1,058 $933 Company use gas cost pass through 107 94

Total Cost of Service including Company Use Gas Cost $1,165 $1,027

The following explains the various components of PNG(N.E.)’s Tumbler Ridge division Test Year 2009 cost of service as summarized above. PNG(N.E.) notes two significant cost increases in Test Year 2009 compared to NSP 2008. Depreciation expense is higher by $12,000 and a depreciation credit adjustment deferral account of $80,000 was fully amortized in 2008. The cessation of this credit deferral account is the main reason why amortization expense is increasing by $48,000 in 2009 compared to 2008. These two items alone account for $60,000 of the $125,000 cost of service increase from 2008 to 2009.


OPERATING EXPENSES

$000’s

Cost Element Test Year 2009

NSP 2008

2009/08 Change

Actual 2007

Actual 2006

Actual 2005

Actual 2004

621 – Processing $270 $240 $30 269 263 $206 $208

665 - Pipelines 12 37 (25) 6 3 2 0

670 – Supervision 29 31 (2) 25 22 19 9

675 – Mains and Services

6 5 1 3 9 9 10

685 – General Operations 19 20 (1) 27 14 49 55

688 – Other General Operations

53 47 6 46 42 47 47

711/713/714 Customer Care 40 44 (4) 36 48 43 68

Add Shared Service Costs 73 72 1 65 67 62 59

Other Including 673 Expenses

51 61 (10) 32 23 41 10

Subtotal $553 $558 ($5) $509 $491 $478 $466

Transfers to Capital ($4) ($6) $2 ($5) ($4) ($4) ($3)

Operating Expenses Excluding Co. use gas cost

$549 $552 ($3) $504 $487 $474 $463


The above figures exclude the cost of Company use gas as it is treated as a pass through cost since it is dependant on prevailing gas supply market prices. The reasons for the cost increases from NSP 2008 to Test Year 2009 are summarized below. Account 621 Forecast processing costs under Account 621 are increasing by $30,000 due to higher outside service costs of $10,000 for transportation and disposal of waste fluids, contaminated filters and other miscellaneous materials, and higher material costs for amine and glycol of $10,000. Increased labour costs account for the remaining increase in Account 621. Account 665 The reduction in Account 665 reflects a reduced need for work on the right-of-way between the processing plant and Tumbler Ridge compared to the last two years. Accounts711/713/714 The above Accounts include customer contracts (711), customer billing (713) and credit and collections (714). An increase in the customer billing costs to reflect the impact of PNG renewing its contract with its billing system application service provider. The original contract had been in place since 1999 and the new contract reflects current market rates and conditions. The higher customer billing costs are more than offset by a reduction in the credit and collections 2009 budget to recognize recent lower actual costs for this function. MAINTENANCE EXPENSES

$000’s

BCUC Account Test Year 2009

NSP 2008


Actual2007

Actual 2006

Actual2005

Actual2004

821 Process Plant $81 $46 $35 $74 $60 $37 $44

All Other 13 17 (4) 23 8 3 8

Total $94 $63 $31 $97 $68 $40 $52

The forecast Test Year 2009 maintenance expenses for Account 821 Process Plant are increasing by $20,000 to reflect the increased cost of materials – most notably replacement parts for pumps and instruments, and higher contractor costs of $15,000 to reflect the forecast


cost of maintaining various instrumentation components of the plant (i.e. fire eyes, gas detectors, etc). ADMINISTRATIVE AND GENERAL EXPENSES The following provides an historical summary of administrative and general costs.

$000’s Cost Element Test Year

2009 NSP 2008

2009/08 Change

Actual 2007

Actual 2006

Actual 2005

Actual 2004

721 Administration $52 $46 $6 $46 $42 $35 $37

722 Audit Fees 10 7 3 4 8 3 3

723 Insurance 12 12 0 13 14 18 30

725 Employee Ben. 49 49 0 56 60 59 57

728 General 12 11 1 10 10 7 7

Sub-total $135 $125 $10 $129 $134 $122 $134

Less transfers to Capital (4) (6) 2 ($5) ($5) (3) (2)

Total $131 $119 $12 $124 $129 $119 $132

Administrative and general costs, net of transfers to capital, have increased from $119,000 under NSP 2008 to $131,000 in Test Year 2009, an increase of $12,000. The increase reflects higher administrative shared services charged by PNG (i.e. the parent company of PNG(N.E.)) under Account 721 of $6,000 and higher shared service costs of $1,000 for Account 728. The higher Account 721 costs reflect head office cost increases for PNG for a staff addition to comply with more detailed financial and corporate reporting requirements. Account 728 costs are increasing to reflect corresponding increases faced by PNG. Account 722 costs are increasing by $3,000 due to higher audit fees as a result of quarterly reviews being performed by PNG(N.E.)’s external auditors.


SHARED SERVICE CHARGES BY PACIFIC NORTHERN GAS LTD. (“PNG”)

The PNG-West 2009 revenue requirements application narrative contains a detailed description of how PNG determines what to charge PNG(N.E.) for services provided by PNG to PNG(N.E.). The PNG-West evidence is incorporated into this Application by reference. The following Table summarizes the shared service charges allocated by PNG to PNG(N.E.)’s Tumbler Ridge division over the 2005 to 2009 period.

$000’s Allocated

Costs Test Year

2009 NSP 2008

2009/08 Change

Actual 2007

Actual 2006

Actual2005

721 Administration Benefits

$43

9

38 8

$5 1

36 9

$34

6

$28

6 685 General Ops. Benefits

28 6

28 8

0

(2)

23 7

26 7

25 6

711/713/714 Customer Care Benefits

32 6

30 7

2

(1)

29 7

27 7

26 5

728 Corporate

5

4

1

4

3

–

Total Allocated

Benefits

108 21

100 23

8

(2)

92 23

90 20

79 17

Total

$129

$123

$6

$115

$110

$96

Shared service charges by PNG to PNG(N.E.)’s Tumbler Ridge division are projected to increase in 2009 from 2008 levels primarily due to cost increases facing PNG. The reason for the cost increases are provided in the PNG-West 2009 revenue requirements application.


TRANSFERS TO CAPITAL

($000’s)

Cost Element Test Year

2009 NSP 2008

2009/08 Change

Actual 2007

Actual 2006

Actual 2005

Operating

$4

$6

$2

$4

$4

$4

Administration

$4

$6

$2

$5

$5

$3

% of Overhead Allocated

3.92%

5.92%

(1.2%)

4.5%

4.5%

3.2%

The allocation of overhead to capital projects for Test Year 2009 has been calculated using a rate of 3.92 percent, compared to 5.92 percent in 2008. The transfer to capital rate is based upon the budgeted component of direct labour in capital projects expected to be completed during the year. PNG(N.E.) is requesting Commission approval to fix the transfer rate for 2009 at 3.92 percent of actual overhead expenses. This figure will be updated when the final 2009 regulatory schedules are filed with the Commission. PROPERTY TAXES

$000’s Cost

Element Test Year

2009 NSP 2008


Actual 2008

Actual 2007

Property Taxes $59 $55 $4 $57 $52

1% in Lieu 20 24 (4) 24 17

Total $79 $79 0 $81 $69

Actual 2008 property taxes were higher than forecast under NSP 2008. The Test Year 2009 provision is based on a 3 percent increase on actual 2008 property taxes having regard to the Province’s freeze on assessed values, additions of new property and inflation adjustments in mill rates. The in the 1 percent in lieu tax is based on revenues in 2007.


DEPRECIATION

Test Year 2009

NSP 2008


$119,000 $107,000 $12,000 Depreciation expense is calculated using the applicable fixed percentage rate times the gross plant cost, for each category of plant asset. Depreciation expense is higher in Test Year 2009 primarily due to a higher gross plant in service. Specifically, gross plant is projected to total $8,575,000 at year end 2009 compared to $8,363,000 at year end 2008, an increase of $212,000. AMORTIZATION

Test Year 2009

NSP 2008


($39,000) ($87,000) $48,000 The amortization expense details are provided under Tab 2. The major changes from NSP 2008 to Test Year 2009 are summarized in the Table below:

Amortization Expense ($000’s)

Deferral Account Test Year 2009

NSP 2008


Industrial Customer Deliveries ($20) ($7) ($13) Property Tax 2 0 2 Bill 198 Compliance 0 0 0 BCUC Hearing 0 0 0 BCUC Fees (3) 0 (3) Short Term Interest 1 1 0 Long Term Interest 0 0 0 Depreciation Adjustment 0 (81) 81 Cost of Service ($19) 0 (19) IFRS

Total ($39) ($87) $48


The Industrial Customer Deliveries deferral account credit increased in 2008 due to CNRL taking more gas than budgeted. PNG is recommending a two year amortization of this account. Property taxes in 2008 were higher than budgeted resulting in a debit deferral which is being amortized in 2009. The depreciation credit deferral account was fully amortized in 2008. The Cost of Service deferral account was set up in 2007. PNG(N.E.)’s 2008 revenue requirements application provided for deferring the amortization of this credit to 2009. PNG is recommending this deferral account be amortized over two years commencing with 2009. The IFRS deferral account is a new deferral account. PNG(N.E.) is seeking approval to record its incremental costs of adopting International Financial Reporting Standards. Commencing with the first quarter in 2011, PNG(N.E.) will be required to show comparative financial information in compliance with IFRS. Changing PNG(N.E.)’s financial statements requires incremental accounting assistance, the cost of which will be recorded in the IFRS deferral account. PNG(N.E.) is delaying commencement of amortization until 2010. The 2010 revenue requirements application will include a proposed amortization period for these costs. PNG(N.E.) is seeking Commission approval of this deferral account as the conversion costs are not expected to be ongoing and given the nature of the project, these costs are difficult to forecast. The PNG-West NSP 2008 settlement agreement contained some commentary on the criteria for setting up new deferral accounts. It was noted that expenditures requiring multi-year amortization and which would not lead to a capital/plant addition, should be set up as a non-rate base deferral account attracting return equivalent to AFUDC. Based on these parameters the IFRS deferral account could be set up as non rate base deferral account attracting AFUDC. Given the fact the accounting work associated with complying with Bill 198 is very similar to the accounting work required to comply with IFRS, PNG(N.E.) is requesting Commission approval to set up the IFRS deferral account as rate base account. The impact on the cost of service is virtually the same as the impact of attracting a return equivalent to AFUDC but it is much easier administratively for PNG(N.E.) to set up the IFRS account consistent with the rate base treatment applied to the Bill 198 compliance deferral account.


OTHER INCOME

Test Year 2009

NSP 2008


$10,000 $12,000 $2,000 The other income forecast, representing penalty fees and connection charges recovered from customers, is based on the historical average over three years. INCOME TAXES

Test Year 2009

NSP 2008


$12,000 ($9,000) $21,000 A number of items affect the determination of the income tax expense. The 2008 to 2009 increase in amortization expense and higher return on common equity are the major reasons why the Test Year 2009 income taxes are forecast to be more than the provision under NSP 2008. RETURN ON COMMON EQUITY

Test Year 2009

NSP 2008


Rate of Return on Equity 9.12% 9.27% 0.15% Common Equity Thickness 36% 36% 0 Common Equity Thickness $587,000 $527,000 $60,000 Return on Equity $54,000 $49,000 $5,000

The allowed rate of return on equity (“ROE”) is determined each year in November by the Commission’s automatic ROE formula. The reduction in the ROE is offset by higher common equity due to a higher rate base.


CAPITAL STRUCTURE PNG(N.E.) believes that the Tumbler Ridge division common equity component at 36 percent, in combination with the allowed rate of return on common equity at only 65 basis points above the low-risk benchmark utility, significantly under compensates its shareholder and is well below the risk compensation for all other comparable utilities in North America. This same situation applies to PNG(N.E.)’s Fort St. John/Dawson Creek division. However, given that PNG(N.E.) has concluded it will not apply for common equity changes for the Fort St. John/Dawson Creek division in 2009, PNG(N.E.) is also not applying to change the 36 percent deemed common equity component of the Tumbler Ridge division for 2009. INTEREST EXPENSE

Test Year 2009

NSP 2008


Short-term debt $12,000 $7,000 $5,000 Long-term debt $59,000 $64,000 ($5,000)

The Test Year 2009 short term debt interest expense has increased over 2008 due to the increase in the short-term debt component of rate base. The higher short term debt requirement offsets the impact of lower interest rates forecast in 2009. The interest rate on short-term debt is forecast to average 4.29 percent in 2009 versus a forecast of 4.46 percent under NSP 2008. Short term debt is comprised of customer security deposits and operating line draws. The interest rates on both components of short term debt are forecast to be lower in 2009 (see Tab 5, page 2), consistent with the decreases in the forecast prime rate from the October 2008 Econolink consensus forecast. Long-term debt interest expense has decreased compared to the NSP 2008 provision due to lower interest rates. The average embedded cost of long-term debt is expected to decrease by over 45 basis points due mainly to the forecast reduction in interest rates on PNG(N.E.)’s floating rate debt which are consistent with the decreases in the forecast 90-day T-bill rate from the October 2008 Econolink consensus forecast. PNG(N.E.) will continue to record changes in interest expense due to differences between forecast and actual floating rates in its interest rate deferral accounts.


COMPANY USE GAS COST

Test Year 2009

NSP 2008


$107,000 $94,000 $13,000 The volume of Company use gas forecast for Test Year 2009 is slightly lower than the forecast under NSP 2008. However a higher forecast unit cost of gas and implementation of the carbon tax more than offsets the lower volume forecast, resulting in an overall increase in forecast Company use gas costs. CAPITAL ADDITIONS IN 2009

Test Year 2009

NSP 2008


Additions including overhead $212,000 $184,000 ($33,000)

Less overhead (12,000) (13,000) $1,000

Net $200,000 $171,000 ($32,000) All of the planned capital expenditures for Test Year 2009 are related to sustaining safe, secure and reliable operations. The annual gas processing plant turnaround has a forecast cost of $51,000. Modifications to the plant that occur due to upgrading of effluent handling, is projected to cost $45,000. Replacing H2S detectors due to their obsolescence will be completed at a forecast cost of $20,000. A new skid steer loader which is to be utilized to maintain the plant grounds in a safe and accessible manner year round will be acquired for $56,000. A number of minor capital items account for the remainder of the Test Year 2009 budgeted capital expenditures.


2009 FORECAST GAS DELIVERIES

The Test Year 2009 forecast of gas deliveries is one of the key components of this Application as the forecast determines the projected amount of revenue PNG(N.E.) will receive from its customers during 2009 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 2009 deliveries to the residential and small commercial customers.

GJ’s Customer

Class Test Year

2009 NSP 2008

Normalized 2008

Normalized 2007

Normalized 2006

Residential 87,551 85,466 92,264 86,611 80,624

Small Commercial 45,542 43,281 49,966 50,532 48,200

Normalized Use per Account (GJ/Customer) Customer

Class Test Year

2009 Linear Trend

2009 NSP 2008

Projected 2008*

Actual 2007

Residential 81.0 76.8 79.0 85.1 80.2

Small Commercial 646.9 587.1 627.3 706.7 736.1

*Normalized 2008 and Projected 2008 are based on the sum of normalized deliveries to the end of October 2008 plus budgeted deliveries for the November to December 2008 period. The residential customer Test Year 2009 use per account is consistent with recent historical experience. PNG considers the average of the Projected 2008 and Linear Trend figures establishes a reasonable estimate of the use per account figure to use for forecasting deliveries in 2009 to the small commercial customer class.


Statistics on the number of customers is provided in the following Table:

Customer Counts

Customer Class

Average for Test Year

2009

Projected Year-end

2008

Projected Weighted

Average 2008

Year-end 2007

Residential 1,081 1,080 1,084 1,086

Small Commercial 70 70 70 71

The Test Year 2009 forecast is compared to actual deliveries for 2005 to 2008 in the following table:

GJ’s Customer

Class Test Year

2009 Projected

2008* Actual 2007

Actual 2006

Actual 2005

Residential 87,551 89,819 83,958 76,301 71,507 Small Commercial 45,542 48,663 49,070 42,978 25,604

*Projected 2008 is the sum of actual deliveries to the end of October 2008 plus budgeted deliveries for the November to December 2008 period. Large Commercial Sales and Industrial Transportation Service Customers

The following summarizes the projected Test Year 2009 deliveries to the large commercial sales and industrial transportation service customers together with NSP 2008 and projected 2008 deliveries:

GJ’s Customer

Class Test Year

2009 NSP 2008

Projected 2008*

Large Commercial 24,500 16,000 28,538

Industrial T-Service 750,000 680,000 883,280

*Projected 2008 is the sum of actual deliveries to the end of October 2008 plus budgeted deliveries for the November to December 2008 period.


The above forecasts for 2009 are based on a review of historical gas deliveries to these customer classes and on discussions with the customers. Under Decision 2007 a gas deliveries deferral account was approved to record the difference between forecast and actual deliveries to the industrial transportation service customer. This deferral account was maintained in 2008. PNG is requesting Commission approval to continue this deferral account in 2009. PNG considers it is reasonable to set the Test Year 2009 gas requirements forecast at 750,000 GJ even though actual deliveries in 2008 are forecast at 883,280 GJ. PNG considers it prudent to underestimate somewhat in case the customer reverts to lower historical gas consumption patterns. In other words, PNG(N.E.) would rather plan for a credit deferral and minimize the chance of a debit deferral.


RATE MATTERS Allocation of Revenue Deficiency

PNG(N.E.) has allocated the 2009 revenue deficiency to its customers using the projected 2009 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 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 together with the split between sales and transportation service deliveries. This enables one 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. RSAM Rate Rider The Summary of Proposed Rates Effective January 1, 2009 shows a separate line for the 2009 RSAM rate rider which is based on recovering the estimated year-end 2008 RSAM balance in equal amounts over the 2009 to 2011 three year period. The derivation of the proposed 2009 RSAM rate rider is provided in a Table under Tab Rates. The RSAM rider calculation will be updated to reflect the most recent information available when the final 2009 regulatory schedules are filed with the Commission to set rates effective January 1, 2009.


2008/2009 Gas Supply Cost Charge Changes/GCVA Riders The gas supply cost recovery rates indicated in the “Summary of Proposed Rates Effective January 1, 2009” were calculated using PNG’s gas cost flow through model updated to reflect the 2008/2009 gas supply and price arrangements entered into by PNG with its gas suppliers and to reflect the impact of the forecast gas prices contained in a forward gas price strip dated November 24, 2008. PNG(N.E.)’s revenue requirement model is designed to show the recovery of forecast gas supply costs on a flow through basis. In other words, the net margin (i.e. gross revenue less forecast cost of sales) will be the same regardless of what forward gas supply prices are used by PNG(N.E.) to calculate gas supply costs. The gas supply cost rates and GCVA riders shown in the “Summary of Proposed Rates Effective January 1, 2009” are based on the November 24, 2008 forward gas prices. The GCVA riders shown in this Application are projected based on current estimated balances in the respective GCVA deferral accounts at year end 2008. It is anticipated that PNG’s fourth quarter 2008 gas supply cost report to the Commission, to be filed in early December 2008, will contain proposed gas supply cost recovery rates and GCVA rate riders equivalent to those shown under Tab Rates. A Table under Tab Rates entitled “Derivation of Test Year Forecast Gas Supply Cost” shows the derivation of the cost of sales figure shown at line 16 of Schedule 1 under Tab 1. The forecast deliveries by customer class times the indicative gas supply prices by customer class generates the cost of sales figure. Determination of 2009 Unit Company Use Gas Cost Rate The 2009 projected cost of Company use gas is based on forecast gas prices 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, except its one transportation service customer, to determine the recovery rate to be embedded in the rates. The transportation service customer supplies their share of Company use gas in kind.


Bill Comparison of Current Rates and January 2009 Rates PNG includes under Tab Rates a comparison of the projected annual gas bills for residential and small commercial customers using current rates and proposed January 1, 2009 rates. The average uses per account reflected in the calculations are the same as the figures used for forecasting gas deliveries to these customer classes in 2009. The average rate increase for residential customers is estimated to be 6.7 percent on the delivery charge component of rates or $32.12 per year for an average customer. If current gas cost recovery rates and GCVA rate riders change effective January 1, 2009 as shown in the rates summary, there will an overall bundled rate decrease of 5.5 percent including the impact of the reduction in the RSAM rate rider. This assumes a bundled average rate of $11.27/GJ which is $6.85/GJ lower than the electricity equivalent rate of $18.12/GJ assuming a 90 percent gas to electricity efficiency factor and using the trailing block electricity rate applicable under the residential inclining block rate structure. The small commercial customer average rate increase is estimated to be 6.8 percent on the delivery charge component of rates or 193.88 per year for an average customer. If current gas cost recovery rates and GCVA rate riders change effective January 1, 2009 as shown in the rates summary, there will an overall bundled rate decrease of 7.3 percent including the impact of the reduction in the RSAM rate rider. This assumes a bundled average rate of $9.59/GJ which is $8.90/GJ lower than the electricity equivalent rate of $18.49/GJ assuming a 90 percent gas to electricity efficiency factor. Demand Side Management Section 4 of the NSP 2008 settlement agreement stated the following with respect to Demand Side Management:

“Resolution PNG(N.E.) will continue to participate in DSM coordination activities and provide a report to the Commission no later than its next revenue requirements application on its efforts in this regard as they pertain to the Fort St. John/Dawson Creek division.”

PNG(N.E.) has not filed a formal report with the Commission regarding its participation in various groups looking at DSM initiatives. The following summarizes the groups that PNG’s Director of Regulatory Affairs and Gas Supply and Manager Community Relations and Administration have been involved with to one degree or another:


• BC Partnership for Energy Conservation and Efficiency

• Industrial Energy Efficiency Working Group

• Working Group on the Built Environment

• Measurement, Analysis and Reporting Task Force Day to day workloads have not afforded the time to enable PNG to participate fully in the groups noted above. PNG(N.E.) has attempted to keep informed by reviewing meeting materials and participate in meetings by telephone where time permits. PNG(N.E.) is more willing to consider implementing DSM programs as its rates are much more competitive with electricity rates compared to the PNG-West division rates. In other words, the PNG(N.E.) division has some room in its rates to bear the incremental cost of DSM programs to encourage gas conservation. For example, PNG(N.E.) considers that DSM programs that encourage consumers to choose the most efficient natural gas appliances, such as high efficiency furnaces and water heaters, which will also have the fewest greenhouse gas emissions, may have merit in its service area. However, PNG(N.E.) is concerned that its small customer base of just under 17,000 customers, makes it difficult to justify the cost of implementing any one particular DSM program. PNG(N.E.) encourages the Province to consider administering DSM programs on a province wide basis allowing each utility to opt in and provide the capital needed to support efficient consumer choices. PNG(N.E.) will continue to participate in and/or monitor development of, as appropriate, the Province’s plans for implementation of the Energy Plan policies related to DSM and utility rate structure changes, but submits that additional independent DSM activity is not warranted at this point. Commission Orders Sought by PNG(N.E.)

PNG(N.E.) is seeking the following Commission approvals under this Application:

1. Approval on an interim basis pursuant to section 89 of the Utilities Commission Act and on a permanent basis pursuant to section 58 of the Utilities Commission Act of the delivery charge, Company use and RSAM rates effective January 1, 2009 as set forth in the Table under Tab Rates entitled “Summary of Proposed Rates Effective January 1, 2009”.

2. Approval of a an overhead capitalization rate of 3.92 percent, subject to modification upon filing of the final 2009 revenue requirements application regulatory schedules.


3. Approval of the deferral accounts and amortization expenses for 2009 as set forth in under

Tab 2, pages 8 and 9 with the following specific approvals:

• approval of a deferral account to record PNG(N.E.)’s costs incurred in 2008 and forecast to be incurred in 2009 and beyond to convert to International Financial Reporting Standards in 2011 with amortization to commence subsequent to 2009 based on a future application by PNG.; and

• approval to amortize of the Industrial Customer Deliveries Deferral account balance and the 2007 cost of service deferral account credit over two years commencing with 2009.

4. Approval to continue the industrial customer transportation service deliveries deferral account in 2008.

5. Approval to continue the unaccounted for gas volume deferral account to record the difference between forecast and actual unaccounted for gas (“UAF”) volumes in Test Year 2009 based on using a 0 percent of deliveries UAF loss factor for 2009 and requiring PNG(N.E.) to apply for Commission approval to record actual 2009 UAF losses above 1.0 percent in the deferral account.

All of which is respectfully submitted DATED at Vancouver, British Columbia this 27th day of November 2008. 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. #950 - 1185 West Georgia Street Vancouver, British Columbia V6E 4E6 Telephone: (604) 691-5673 Fax: (604) 697-6210 E-mail: [email protected]

Tab RatesTumbler Ridge2009 Rate App.

Page 1

Residential (RS1)


Delivery Charge 4.045 0.368 4.413 0.368Company Use 0.647 0.029 0.676 0.029GCVA Co. Use Rider (0.178) (0.170) (0.348) (0.170)RSAM 0.081 (0.155) (0.074) (0.155)Interim Rate Refund Rider 0.000 0.000Subtotal Delivery 4.595 0.368 (0.296) 4.667 0.072

Gas Supply Commodity 6.668 0.075 6.743 0.075 GCVA Commodity Rider (0.600) (0.804) (1.404) (0.804) Subtotal Commodity 6.068 0.000 (0.729) 5.339 (0.729)

Total 10.663 0.368 (1.025) 10.006 (0.657)

Small Commercial (RS2)


Delivery Charge 3.571 0.271 3.842 0.271Company Use 0.647 0.029 0.676 0.029GCVA Co. Use Rider (0.178) (0.170) (0.348) (0.170)RSAM 0.081 (0.155) (0.074) (0.155)Interim Rate Refund Rider 0.000 0.000Subtotal Delivery 4.121 0.271 (0.296) 4.096 (0.025)


Total 10.189 0.271 (1.025) 9.435 (0.754)



Delivery Charge 2.996 0.226 3.222 0.226Company Use 0.647 0.029 0.676 0.029GCVA Co. Use Rider (0.178) (0.170) (0.348) (0.170)Interim Rate Refund Rider 0.000 0.000Subtotal Delivery 3.465 0.226 (0.141) 3.550 0.085


Total 9.533 0.226 (0.870) 8.889 (0.644)

Industrial Transport (CNRL)

Monthly Fixed Charge $10,000.00 $10,000.00 $0.00Delivery Charge 0.217 0.023 0.240 0.023

Proposed Rates January 1, 2009 Rate Changes

Customer Class Rates Effective October 1, 2008



Change

Pacific Northern Gas (N.E.) Ltd.(Tumbler Ridge Division)


Rate Schedules-09TR


Page 2




Annual Use $ $ $ %Residential: 81.0 GJ Monthly Fixed Charge @ 8.50 / mo. 1.259 102.00 1.259 102.00 0.00 Delivery Charge 4.692 380.05 5.089 412.17 32.12 GCVA Co. Use Rider (0.178) (14.42) (0.348) (28.19) (13.77) RSAM Rider 0.081 6.56 (0.074) (5.99) (12.55)

474.20 479.99 5.79 1.2%

Gas Supply Charge 6.668 540.11 6.743 546.18 6.07 GCVA Rider (0.600) (48.60) (1.404) (113.72) (65.12)

491.51 432.46 (59.05) -12.0%

$11.922 /GJ $965.70 $11.265 /GJ $912.45 ($53.26) -5.5%Small Commercial: 646.9 GJ Monthly Fixed Charge @ 8.50 / mo. 0.158 102.00 0.158 102.00 0.00 Delivery Charge 4.218 2,728.62 4.518 2,922.51 193.88 GCVA Co. Use Rider (0.178) (115.15) (0.348) (225.12) (109.97) RSAM Rider 0.081 52.40 (0.074) (47.87) (100.27)

2,767.87 2,751.52 (16.36) -0.6%

Gas Supply Charge 6.668 4,313.53 6.743 4,362.05 48.52 GCVA Rider (0.600) (388.14) (1.404) (908.25) (520.11)

3,925.39 3,453.80 (471.59) -12.0%

$10.347 /GJ $6,693.26 $9.592 /GJ $6,205.32 ($487.95) -7.3%


$ / GJ

Proposed RatesJan. 1, 2009

$ / GJ


Permanent RatesOct. 1, 2008

TR Bill CompBillcomparisons-09


Page 3

2009 2009 Allocation of Rate ChangesTest Year Gross Revenue for Revenue

Customer Classification Gas Deliveries Margin Deficiency Sufficiency(GJ) ($) ($) ($/GJ)

Residential Sales (RS1) 87,551 523,611 32,182 0.368Small Commercial Sales (RS2) 45 542 200,595 12,329 0.271Large Commercial Sales (RS3) 24 500 90,167 5,542 0.226Total Sales 157 593 814,373 50,052

Industrial Transport (CNRL) 750 000 282,750 17,378 0.023

TOTAL 907 593 1,097,123 67,430


SUMMARY OF GAS DELIVERY CHARGE PROPOSED RATE CHANGESEFFECTIVE JANUARY 1, 2009


Page 4

2009 Test YearCustomer Classification Gas Deliveries Revenue Cost of Gas Gross Margin

(GJ) ($) ($) ($)

Residential Sales (RS1) 87,551 1,113,970 590,359 523,611Small Commercial Sales (RS2) 45 542 507,682 307,087 200,595Large Commercial Sales (RS3) 24 500 255,370 165,204 90,167Industrial Transport (CNRL) 750 000 282,750 0 282,750Total 907 593 2,159,772 1,062,649 1,097,123


SUMMARY OF REVENUE, COST OF GAS, GROSS MARGIN


Page 5

Test Year 2009Forecast Test Year Test Year Average Test Year

Customer Count + Effective Customer = Weighted Average x Use Per Account = DeliveriesCustomer Classification At Dec. 31st, 2008 Additions Customer Count (GJ) (GJ)

Sales:Residential (Rate 1 ) 1,080 1 1,081 81.0 87,551

CommercialSmall Commercial (Rate 2) 70 0 70 646.9 45,542Large Commercial Firm (Rate 3) 24,500Total Commercial

Subtotal Sales 157,593

2009Test YearDeliveries

(GJ)Transport

CNRL 750,000

Total 907,593


Derivation of Test Year Forecast Gas Deliveries



Page 6

2009 Current Weighted TotalTest Year Delivery Avg. Delivery Test YearDeliveries Charge Delivery Customer Current Fixed Charge & Fixed Charge Gross

Customer Classification (GJ) $ / GJ Margin Count Fixed Charge Margin Margin MarginSales:Residential (Rate 1 ) 87,551 4.721 413,328 1,081 8.50 110,279 523,607 523,607

CommercialSmall Commercial (Rate 2) 45,542 4.247 193,417 70 8.50 7,107 200,524 200,524Large Commercial (Rate 3) 24,500 3.672 89,964 3 8.50 306 90,270 90,270Total Commercial 70,042 283,381 73 7,413 290,794 290,794

Subtotal Sales 157,593 696,709 117,692 814,402 814,402

2009 Current Weighted TotalTest Year Delivery Avg. Delivery Test YearDeliveries Charge Delivery Customer Current Fixed Charge & Fixed Charge Gross

(GJ) $ / GJ Margin Count Fixed Charge Margin Margin MarginTransportation:

CNRL 750,000 0.217 162,750 1 10,000 120,000 282,750 282,750

Subtotal Transportation 750,000 162,750 120,000 282,750 282,750

TOTAL 907,593 859,459 237,692 1,097,152 1,097,152





Page 7

2009Test Year Gas Cost TotalDeliveries Charge Gas Cost

Customer Classification (GJ) ($ / GJ) ($)

Residential (Rate 1 ) 87,551 6.743 590,356

CommercialSmall Commercial (Rate 2) 45,542 6.743 307,090Large Commercial (Rate 3) 24,500 6.743 165,204Total Commercial 70,042 472,293

Total Tumbler Ridge 157,593 1,062,650




Company Company Gas Supply CompanyCustomer Classification Commodity Use Gas Commodity (1) Use Gas (2) Commodity Use Gas

($/GJ) ($/GJ) ($/GJ) ($/GJ) ($/GJ) ($/GJ)

Residential (RS1) 6.668 0.647 6.743 0.676 0.075 0.029

Small Commercial (RS2) 6.668 0.647 6.743 0.676 0.075 0.029

Large Commercial (RS3) 6.668 0.647 6.743 0.676 0.075 0.029

Industrial Sales (RS4) 6.668 0.647 6.743 0.676 0.075 0.029

Notes:1.The commodity charges are payable for each GJ of gas purchased by PNG(N.E.). The commodity charges represent PNG(N.E.)'s projection of its commodity costs based on its projected gas supply purchases. 2.The unit company use gas cost is determined by dividing the projected cost of company use gas by gas sales.

DETERMINATION OF GAS SUPPLY COST RATE CHANGES EFFECTIVE JANUARY 1, 2009

(Tumbler Ridge Division)Pacific Northern Gas (N.E.) Ltd.


Gas Supply CostsRates


IndicativeGas Supply Cost Rate Changes

Effective January 1, 2009

Gas Supply CostsProposed Rates

Proposed Rates Effective January 1, 2009

Retail Rate Changes-TumblerTR-09


Page 9

Demand Cost $0

Commodity Cost $91,759B.C.S.S. Tax $6,424Ice Levy $368Carbon Tax $8,050Total Company Use Gas Cost $106,601

Total Company use gas requirement 13 608 GJDeliveries 157 593 GJ

2009 Unit Company Use Gas Cost Rate$0.676 /GJ $106,601

157 593

Commodity Cost of Company Use Gas per GJ Purchased$6.743 /GJ $91,759

13 608


Determination of 2009 Unit Company Use Gas Cost Rate



Page 10

Actual RSAM Balance at Year-end 2007 $88,198 (66,595) $21,603

Estimated RSAM Recovery / Deferral in 2008 ($27,478) (23,778) ($51,256)

Estimated RSAM Balance at Year-end 2008 $60,720 ($90,373) ($29,654)

Years of Amortization 3

RSAM Balance divided by 3 Equals Amortization ($9,885)

Forecast 2009 Deliveries 87,551 45,542 133,093

One Year of Amortization divided by 2009 Deliveries equals RSAM Rate Rider ($/GJ) (0.074)

Small Commercial


Determination of 2009 Revenue Stabilization Adjustment Mechanism (RSAM) Rider

Residential Total


Page 11

STATION #2 AECOCDN$/GJ CDN$/GJ

Jan-09 7.5167 7.3667Feb-09 7.4636 7.3936Mar-09 7.2326 7.3526Apr-09 6.9752 7.1356May-09 7.0072 7.1672Jun-09 7.1238 7.2838Jul-09 7.2580 7.4180Aug-09 7.3746 7.5346Sep-09 7.4271 7.5871Oct-09 7.5321 7.6921Nov-09 8.1976 8.0576Dec-09 8.6284 8.4884Average 7.4781 7.5398


Forward Gas Price StripNovember 24, 2008

Tab 1Tumbler Ridge2009 Rate App.

Page 1


UTILITY INCOME & RETURN

SCHEDULE 1(000's)


1 Energy sales (TJ) 158 145 Tab Rates, page 52 Average rate per GJ $12.23 $11.1234 Transportation service (TJ) 750 680 Tab Rates, page 55 Average rate per GJ $0.40 $0.3967 Total deliveries (TJ) 908 825 Tab Rates, page 589 Utility revenue

10 Energy sales $1,877 $1,642 Tab Rates, page 411 Interim rates - sales 50 (33) Tab Rates, page 312 Transportation service 283 279 Tab Rates, page 413 Interim rates - transportation 17 (12) Tab Rates, page 31415 2,227 1,876 16 Cost of sales 1,063 850 Tab Rates, page 4 & 71718 Gross margin 1,165 1,027 1920 Operating expenses 655 646 Tab 1, page 2, line 621 Maintenance expenses 94 63 Tab 1, page 2, line 1022 Admin. & general expenses 131 119 Tab 1, page 2, line 1623 Property taxes 79 79 Tab 1, page 6, line 424 Depreciation 119 107 Tab 2, page 6, line 4925 Amortization (39) (87) Tab 2, page 9, line 2126 Investment income, other revenue (10) (12) Tab 1, page 7, line 727 Cost of Service Deferral28 1,028 915 2930 Earned return before income taxes 136 112 31 Income taxes 12 (9) Tab 3, page 1, line 143233 Earned return $125 $1203435 Utility rate base $1,632 $1,465 Tab 2, page 1, line 203637 Return on rate base 7.66% 8.21% Tab 5, page 1, line 23


Page 2


SUMMARY OF OPERATING, MAINTENANCE& ADMINISTRATIVE & GENERAL EXPENSES

(000's)


1 OPERATING EXPENSES2 - wages 233 2263 - gas 107 94 4 - transferred to capital (4) (6) 5 - other 320 333

6 Total Operating 655 646

7 MAINTENANCE EXPENSES8 - wages 25 249 - other 69 39

10 Total Maintenance 94 63

11 ADMINISTRATIVE AND GENERAL EXPENSES12 - wages 0 013 - benefits 49 4914 - transferred to capital (4) (6) 15 - other 85 76

16 Total Admin & General 131 119

17 TOTAL EXPENSES $880 $829

Net of Transfers & Gas 781 747


Page 3


OPERATING EXPENSES

(000's)


1 621 Processing 270 2402 Process plant - gas 107 94

376 334

3 664 Communications 2 24 665 Pipelines 12 375 Pipelines - Gas 0 06 667 Regulating Stations 11 157 Total transmission 24 53

8 670 Supervision 29 319 673 Removing & resetting meters 22 2510 674 Service on customer premises 2 111 675 Mains and services 6 512 677 Regulating stations 0 013 679 Other 0 0


15 684 Communications 0 116 685 General systems operations 19 2017 Shared Services from Parent 34 36 18 688 Other general operations 53 4719 689 Transferred to capital (4) (6)


21 701 Advertising 1 122 702 Demonstration and selling 1 123 709 Other 0 0

24 Total sales 2 2

25 710 Customer Accounting 0 126 711 Customer contracts 0 127 Shared Services from Parent 10 1028 712 Meter reading 12 1429 713 Customer billing 36 3430 Shared Services from Parent 23 2131 714 Credit and collections 4 932 Shared Services from Parent 5 633 718 Uncollectible accounts 1 1

34 Total customer accounting 91 96

35 Total operating $655 $646


Page 4


MAINTENANCE EXPENSES

(000's)


1 821 Process plant 81 46

2 864 Communications 0 03 865 Pipe lines 1 14 866 Compressors 0 05 867 Regulating stations 2 1


7 872 Structures 5 58 874 Customer premises 0 09 875 Mains and services 1 110 877 Regulating stations 0 011 878 Meters 2 612 879 Other 0 0


14 884 Communications 2 215 885 General 1 1


17 Total maintenance $94 $63


Page 5


ADMINISTRATIVE AND GENERAL EXPENSES

(000's)


1 721 Administration 0 0 Shared Services from Parent 52 46

2 722 Audit fees 10 7

3 723 Insurance 12 12

4 724 Reserve for damages 0 0

5 725 Employee benefits 49 49

6 728 Shared Services from Parent 5 4 7 Regulation 6 68 Donations 1 1

9 729 Transferred to capital (4) (6)

10 Total administrative and general $131 $119


Page 6

(000's)


1 PROPERTY TAXES2 Regular $59 $553 Other 1% in lieu 20 24

4 TOTAL $79 $79

TAXES OTHER THAN INCOME TAXES

(Tumbler Ridge Division)Pacific Northern Gas (N.E.) Ltd.


Page 7


MISCELLANEOUS OPERATING REVENUE

(000's)


1 Penalty charges $7 $9

2 Connection Fees $2 3

3 Rents 0 0

4 Overheads recovered 0 0

5 Automotive surcharges 0 0

6 Other 0 0

7 $10 $12



Page 1


UTILITY RATE BASE

SCHEDULE 2(000's)


1 Plant in service beginning of year $8,363 $8,125 Tab 2, page 2, line 502 Additions 212 184 Tab 2, page 3, line 503 Disposals - - Tab 2, page 2, line 5045 Plant in service end of year 8,575 8,309 6 Accumulated depreciation 5,369 5,276 Tab 2, page 6, line 3978 Net plant in service end of year 3,205 3,033 9

10 Net plant beginning of year 3,160 3,004 Tab 2, pages 3 & 5, lines 50 & 391112 Net plant in service midyear 3,183 3,018 13 Contributions for construction (1,064) (1,118) Tab 2, page 15, line 1314 Unamortized deferred charges (44) 16 Tab 2, page 9, line 1115 Deferred income taxes (415) (415) 16 Reserve for damages (155) (155) 17 Cash working capital 127 118 Tab 2, page 10, line 818 Other working capital - - 1920 Utility rate base, midyear $1,632 $1,465


Page 2

Forecast

Description

Actual Jan/08 Beginning Balance Additions Allocations Transfers Retirements


Line1 Processing plant2 410 Land 3 33 411 Land Rights4 412 Compressor Structures 34 345 413 Regulating Structures 75 756 417 Regulating Equipment 30 307 418 Purification Equipment 2,982 94 4 3,08089 3,125 94 4 3,223

10 Transmission plant11 460 Land12 461 Land rights13 462 Compressor structures14 463 Regulating structures15 465 Mains 1,716 1,71616 466 Compressor equipment 4 417 467 Regulating equipment 84 56 2 14218 468 Communications19 469 Other

20 1,805 56 2 1,86321 Distribution plant22 471 Land rights 2 223 472 Structures 79 111 5 19424 473 Services 579 57925 474 House installations 259 25926 475 Mains 984 98427 476 Compressor equipment28 477 Regulating equipment 194 56 2 25229 478 Meters 240 24030 479 Other

31 2,336 167 7 2,51032 General plant33 480 Land 23 2334 481 Land rights35 482 Structures 402 40236 483 Office equipment 31 3137 484 Transportation equipment 125 (36) (44) 4538 485 Heavy work equipment 37 3739 486 Tools 72 12 8440 487Computer equipment 27 2741 488 Communications 117 11742 489 Other0

43 835 12 (36) (44) 76744 Construction overheads45 Unallocated construction costs46 System operations transfers 5 (5)47 Administrative transfers 5 (5)48 Depreciation 3 (3)

49 13 (13)

50 8,101 342 () (36) (44) 8,363


GAS PLANT IN SERVICE2008

($ 000's)


Page 3(Tumbler Ridge Division)

GAS PLANT IN SERVICE2009

($ 000's)

Description

Forecast Jan/08

Beginning Balance Additions Allocations Retirements


Line1 Processing plant2 410 Land 3 33 411 Land Rights 3 34 412 Compressor Structures 34 345 413 Regulating Structures 75 756 417 Regulating Equipment 30 307 418 Purification Equipment 3,080 117 10 3,20789 3,223 117 10 3,349

10 Transmission plant11 460 Land12 461 Land rights13 462 Compressor structures14 463 Regulating structures15 465 Mains 1,716 1,71616 466 Compressor equipment 4 417 467 Regulating equipment 142 14218 468 Communications19 469 Other

20 1,863 1,86321 Distribution plant22 471 Land rights 2 223 472 Structures 194 7 1 20224 473 Services 579 5 58525 474 House installations 259 25926 475 Mains 984 98427 476 Compressor equipment28 477 Regulating equipment 252 25229 478 Meters 240 1 25130 479 Other

31 2,510 23 2 2,53532 General plant33 480 Land 23 2334 481 Land rights35 482 Structures 402 40236 483 Office equipment 31 3137 484 Transportation equipment 45 4538 485 Heavy work equipment 37 56 9339 486 Tools 84 4 8840 487Computer equipment 27 1 2841 488 Communications 117 11742 489 Other0

43 767 61 82844 Construction overheads45 Unallocated construction costs46 System operations transfers 4 (4)47 Administrative transfers 4 (4)48 Depreciation 4 (4)

49 12 (12)

50 8,363 212 8,575

Forecast



Page 4


1 Balance, Beginning of Year 8,363 8,101

2 CIAC Balance, Beginning of Year (4,245) (4,245)

3Plant Cost, net of CIAC, Beginning of Year 4,118 3,856

4 Additions during year:5 Plant Cost 200 3296 Allocation of overheads 12 13

7 Total Plant Additions 212 342

8 Contributions in Aid of Construction9 Total Additions 212 342

10 Plant Retirements:11 Normal Course (80)12 Deactivated Assets

13 CIAC Retirements

14 Total Retirements (80)


16 Closing balance consists of:

17 Plant Cost 8,575 8,363

18 CIAC (4,245) (4,245)


(000's)

Pacific Northern Gas (NE) Ltd.Tumbler Ridge

GAS PLANT IN SERVICE - CONTINUITY OF PLANT COST


Page 5

Description

Actual Jan/08 Beginning Balance Provision Transfers Retirements Recoveries

Depreciation Adjustment


Line1 Gathering plant2 412 Compressor Structures 3.00% (9) (1) (10)3 413 Regulating Structures 3.00% (45) (2) (47)4 417 Regulating Equipment 3.00% (6) (1) (7)5 418 Purification Equipment 5.00% (2,464) (38) (2,502)67 (2,524) (42) (2,566)8 Transmission plant9 462 Compressor structures 3.00%

10 463 Regulating structures 3.00%11 465 Mains 2.00% (811) (34) (846)12 466 Compressor equipment 3.00% (2) () (2)13 467 Regulating equipment 3.00% (22) (3) (24)14 468 Communications 5.00%13 469 Other 3.00%1415 (835) (37) (872)16 Distribution plant17 472 Structures 3.00% (21) (2) (23)18 473 Services 2.00% (210) (12) (221)19 474 House installations 3.00% (169) (8) (177)20 475 Mains 2.00% (406) (20) (425)21 476 Compressor equipment 0.00%22 477 Regulating equipment 3.00% (150) (6) (156)23 478 Meters 3.00% (144) (7) (151)24 479 Other 3.00%2526 (1,099) (54) (1,154)2728 General plant29 482 Structures 3.00% (326) (12) (338)30 483 Office equipment 5.00% (13) (1) (14)31 484 Transportation equipment 15.00% (111) (7) 36 44 (4) (41)32 485 Heavy work equipment 5.00% (29) (2) (31)33 486 Tools 5.00% (44) (2) (46)34 487 Computer equipment 20.00% (25) (2) (27)35 488 Communications 5.00% (113) () (114)36 489 Other 5.00%37 (661) (27) 36 44 (4) (612)3839 (5,119) (160) 36 44 (4) (5,203)

40 Amortization of Contributions41 Processing 2,322 2,32242 Transmission 664 34 69843 Distribution 127 11 13844 General 1 145 Total Amortization of Contributions 3,114 45 3,159

46 Accum Depn/Amort (incl contrib) (2,005) (2,044)

47 Amortization of CIAC 45

48 Depreciation capitalized (see calc below) 4 49 Net depreciation expense (111)


CONTINUITY OF(Tumbler Ridge Division)

Forecast


FOR THE YEAR 2008

($ 000's)


Page 6

Description

Forecast Jan/08

Beginning Balance Provision Retirements Recoveries


Line1 Gathering plant2 412 Compressor Structures 3.00% (10) (1) (11)3 413 Regulating Structures 3.00% (47) (2) (50)4 417 Regulating Equipment 3.00% (7) (1) (8)5 418 Purification Equipment 5.00% (2,502) (42) (2,543)67 (2,566) (46) (2,612)8 Transmission plant9 462 Compressor structures 3.00%

10 463 Regulating structures 3.00%11 465 Mains 2.00% (846) (34) (880)12 466 Compressor equipment 3.00% (2) () (2)13 467 Regulating equipment 3.00% (24) (4) (29)14 468 Communications 5.00%13 469 Other 3.00%1415 (872) (39) (911)16 Distribution plant17 472 Structures 3.00% (23) (6) (29)18 473 Services 2.00% (221) (12) (233)19 474 House installations 3.00% (177) (8) (185)20 475 Mains 2.00% (425) (20) (445)21 476 Compressor equipment 0.00%22 477 Regulating equipment 3.00% (156) (8) (163)23 478 Meters 3.00% (151) (7) (159)24 479 Other 3.00%2526 (1,154) (60) (1,213)2728 General plant29 482 Structures 3.00% (338) (12) (350)30 483 Office equipment 5.00% (14) (1) (16)31 484 Transportation equipment 15.00% (41) (4) (45)32 485 Heavy work equipment 5.00% (31) (2) (32)33 486 Tools 5.00% (46) (3) (49)34 487 Computer equipment 20.00% (27) (27)35 488 Communications 5.00% (114) () (114)36 489 Other 5.00%37 (612) (22) (634)3839 (5,203) (167) (5,369)

40 Amortization of Contributions41 Processing 2,322 () 2,32242 Transmission 698 33 73143 Distribution 138 10 14944 General 1 145 Total Amortization of Contributions 3,159 44 3,202

46 Accum Depn/Amort (incl contrib) (2,044) (2,167)

47 Amortization of CIAC 44

48 Depreciation capitalized 4 49 Net depreciation expense (119)

FOR THE YEAR 2009

($ 000's)


CONTINUITY OF(Tumbler Ridge Division)

Forecast



Page 7


1 Balance, Beginning of Year (5 203) (5 119)

2CIAC Accumulated Balance, Beginning of Year 3 159 3 114

3Utility Accumulated Depreciation, Beginning of Year (2 044) (2 005)

4 Depreciation Provision:5 Plant ( 167) ( 160)6 Contributions in Aid of Construction 44 45

7 Depreciation Adjustment Deferral

8 Total Additions ( 123) ( 115)

9 Plant Retirements:10 Normal Course 8011 Deactivated Assets

12 CIAC Retirements

13 Removal Costs

14 Proceeds on Disposals ( 4)

15 Total Retirements 76

16 Balance, End of Year (2 167) (2 044)

17 Closing Balance Consists of:

18 Accumulated Depreciation - Plant (5 369) (5 203)

19 Accumulated Amortization - CIAC 3 202 3 159

20 Balance, End of Year (2 167) (2 044)

Tumbler Ridge

GAS PLANT IN SERVICE - CONTINUITY OF ACCUMULATED DEPRECIATION

(000's)

Pacific Northern Gas (NE) Ltd.

Tab 2 Tumbler Ridge2009 Rate App.

Page 8



YEAR 2008(000's)

Actual Gross ForecastLine Description Balance '07 Additions Tax Amortization Balance '08

1 Rate base items2 Studies 3 0 0 0 33 Line Repair (Babcock) 0 0 0 0 03 Industrial Deliveries (11) (52) 16 (7) (40)4 BCUC Hearing (0) 0 0 0 (0)5 Property tax deferral (0) 2 (1) (0) 26 RSAM 13 (51) 16 0 (22)7 Tumbler Ridge Plant Upset 0 0 0 0 08 Bill 198 Compliance Costs 1 1 (0) 0 19 IFRS 0 0 (0) 0 0

10 5 (100) 31 (7) (57)

11 Average rate base for the year ($26)

12 Interest bearing deferrals13 BCUC Fees (0) (5) 1 (0) (3)14 GCVA (261) 208 (66) 0 (120)15 Depreciation Adjustment (78) 0 0 (80) 116 Short term Interest 1 1 (0) 1 017 Long term Interest 0 (1) 0 0 (1)18 Carbon / Income Tax 0 (1) 0 0 (0)19 Cost of Service (34) (3) 0 0 (37)20 (372) 199 (65) (79) (159)2122 Total deferrals (excl. Debt Issue) ($368) $98 ($33) ($86) ($217)2324 Debt/equity issue costs $6 $0 $0 $1 $4


Tab 2 Tumbler Ridge2009 Rate App.

Page 9



Test Year 2009(000's)

Forecast GrossLine Description Balance '08 Additions Tax Amortization Balance '09

1 Rate base items2 Studies 3 0 0 0 33 Line Repair (Babcock) 0 0 0 0 04 Industrial Customer Deferral (40) 0 0 (20) (20)5 BCUC Hearing (0) 1 (0) 0 06 Property tax deferral 2 0 0 2 07 RSAM (22) 10 (3) 0 (15)8 Tumbler Ridge Plant Upset 0 0 0 0 09 Bill 198 Compliance Costs 1 0 0 0 0

10 IFRS 0 0 (0) 0 011 (57) 11 (3) (18) (31)

12 Average rate base for the year ($44)

13 Interest bearing deferrals14 BCUC Fees (3) (0) 0 (3) (0)15 GCVA (120) 276 (83) 0 7316 Depreciation Adjustment 1 0 0 0 117 Short term Interest 0 2 (0) 1 018 Long term Interest (1) (0) 0 (0) (0)19 Carbon / Income Tax (0) 0 0 (0) 020 Cost of Service (37) (2) 0 (18) (20)21 (159) 276 (83) (21) 552223 Total deferrals (excl. Debt Issue) ($217) $287 ($87) (39) $232425 Debt/equity issue costs $4 $0 $0 1 $3



Page 10


CASH WORKING CAPITAL

FOR THE YEAR ENDED DECEMBER 31, 2009

Line Lag/(Lead) Working No. Particulars Days Expense Capital

1 Revenue 54.0

2 Expense (30.4)

3 Operating working capital 23.6 $2,033 $131

4 Adjustments:

5 Equal Billing Plan adjustment (9)

6 PST, ICEF Levy & Carbon Tax (1)

7 Goods and services tax 5

8 Cash working capital required $127



Page 11


REVENUE LAG DAYS


Line Revenue Normalized ExtendedNo. Revenues Lag days Revenue Revenue

1 Residential - monthly 47.39 $226 $10,7092 - bimonthly 59.88 888 53,173

3 Small commercial - monthly 42.24 $493 20,8454 - bimonthly 64.90 $14 922

5 Large Commercial 41.38 255 10,567

6 Small industrial 72.2 283 20,415

7 Rate increase 54 67 3,641

8 Other operating revenue 54.0 10 536

9 Average revenue lag days 54.0 $2,237 $120,808



Page 12


EXPENSE LEAD DAYS


ExpenseLine (Lead) Normalized ExtendedNo. Revenues Days Expenses Expenses

1 Gas Purchases (40.2) $1,169 ($47,004)

2 Operating payroll (5.0) 258 (1,290)

3 Employee benefits (20.9) 49 (1,033)

4 Uncollectible accounts (54.0) 1 (56)

5 Other operating expenses (31.4) 460 (14,455)

6 Expenses credited/capitalized (10.6) (8) 87

7 Insurance 182.5 12 2,224

8 Property taxes (1.0) 79 (79)

9 Income taxes payable (15.2) 12 (176)

(30.4) $2,033 (61,782)



Page 13


CASH WORKING CAPITAL - GOODS AND SERVICES TAX


Line Taxable G.S.T. Receipt Payment Net WorkingNo. Description Amount @ 5% Lag Days (Lead) Days Lag/(Lead) Capital

1 Revenues2 Residential and commercial $1,927 96 15.6 (30.4) (14.8) (3.9)3 Industrial 300 15 57.0 (60.8) (3.8) (0.2)4 Carbon Tax 95 5 15.7 (30.4) (14.7) (0.2)56 $116 (13.4) ($4.2)789

10 Credit Payment Net Working11 Lag Days Lag Days Lag/(Lead) Capital12 Purchases13 Capital expenditures $200 10 39.6 (1.0) 38.6 1.114 Gas supply 1,169 58 60.8 (25.0) 35.8 5.715 Operating costs 460 23 39.6 (1.0) 38.6 2.41617 $91 36.8 $9.21819 $5.0



Page 14


CASH WORKING CAPITAL - PROVINCIAL SALES TAX & ICEF LEVY


Line Taxable P.S.T. Receipt Payment Net WorkingNo. Description Amount @ 7% Lag Days Lag Days Lag/(Lead) Capital

1 Revenues2 Commercial sales $781 55 16.8 (23.0) (6.2) (0.9)3 Industrial sales 0 - 57.0 (23.0) 34.0 0.04 PST Subtotal 781 55 (0.9)56 ICEF Levy7 @ 0.4%8 Residential sales $1,146 5 14.8 (23.0) (8.2) (0.1) 9 Commercial sales $781 3 16.8 (23.0) (6.2) (0.1)

10 Small Industrial sales $0 - 57.0 (23.0) 34.0 - 11 ICEF Levy Subtotal $1,927 $8 (0.2) 1213 Taxable Carbon14 Gas sales subject to Carbon Tax GJs Tax15 Residential sales - January to June 49 740 $25 14.8 (15.0) (0.2) ($0)16 - July to December 37 811 28 14.8 (15.0) (0.2) (0.0)17 Commercial sales - January to June 39 642 20 16.8 (15.0) 1.8 0.118 - July to December 30 399 23 16.8 (15.0) 1.8 0.119 Carbon Tax Subtotal 157 593 $95 15.7 (15.0) 0.7 $0.22021 PST, ICEF Levy & Carbon Tax Total ($0.9)



Page 15


CONTRIBUTIONS IN AID OF CONSTRUCTION

(000's)


1 Gas Plant In Service2 Beginning balance $4,245 $4,2433 Additions - 22

4 Ending balance $4,245 $4,265

5 Accumulated Amortization6 Beginning balance ($3,159) ($3,114)7 Additions (44) (44)

8 Ending balance ($3,202) ($3,158)

9 Net Total10 Beginning balance $1,086 $1,12911 Additions (44) (23)

12 Ending balance $1,043 $1,107

13 Average balance $1,064 $1,118


Page 1


INCOME TAXES

SCHEDULE 3(000's)


1 Calculation of Taxable Income2 Earned return before income taxes $136 $112 Tab 1, page 1, line 303 Interest (71) (71) Tab 5, page 1, lines 1, 3, 6 & 84 Permanent differences 0 - 5 Timing differences (27) (68) Tab 3, page 1, line 2567 Taxable income $39 ($27)89 Calculation of Income Tax Expense

10 Income taxes payable $12 ($9)11 Part I.3 tax - - 12 Deferred income tax - - 1314 Income tax expense $12 ($9)1516 Particulars of Timing Differences17 A. Tax Effects Subject To Flowthrough18 Depreciation $119 $107 Tab 1, page 1, line 2419 Amortization (39) (87) Tab 1, page 1, line 2520 Capital cost allowance (100) (80) 21 Deferred charges - - 22 Overheads capitalized (7) (7) 23 Other - - 2425 Timing differences (27) (68) 2627 Tax rate 30.00% 31.50%28 Surtax rate 0.00% 0.00%29 Deferred tax rate 30.00% 31.50%


Page 1


COMMON EQUITY

SCHEDULE 4(000's)


1 Opening balance2 Share capital $230 $2303 Contributed surplus - - 4 Retained earnings 340 291 56 570 521 78 Net income $54 $499 Shares Issued (Repurchased) - -

10 Preferred dividends - - 11 Common dividends (18) (36) 1213 Closing balance $605 $534141516 Midyear common equity $587 $527


Page 1


RETURN ON CAPITAL

SCHEDULE 5(000's)


1 Short term borrowings $287 $1562 proportion 17.58% 10.66%3 rate of return 4.28% 4.46% Tab 5, page 2, line 114 return component 0.75% 0.48%56 Long term debt $757 $781 Tab 5, page 3, line 237 proportion 46.42% 53.34%8 rate of return 7.80% 8.25% Tab 5, page 3, line 259 return component 3.62% 4.40%

1011 Common equity $587 $52712 proportion 36.00% 36.00%13 rate of return 9.12% 9.27%14 return component 3.28% 3.34%1516 Total capitalization $1,632 $1,4651718 Return on rate base 7.66% 8.21%1920 Utility rate base $1,632 $1,465 Tab 2, page 1, line 20


Page 2


SHORT TERM DEBT



1 Customer Security Deposits2 Average annual balance $57 $573 Interest rate applicable to deposits 0.47% 1.59%4 Annual Interest Expense $0 $156 Operating Line / Other7 Average annual draw $230 $1008 Interest rate 5.22% 6.09%9 Annual Interest Expense $12 $6

1011 Average short term interest rate 4.28% 4.46%


Page 3


LONG TERM DEBT



1 Secured Debentures Series 20182 Liability beginning of year $561 $5853 Sinking fund payments (24) (24) 4 Average Capitalization 557 581 5 Annual Interest Expense 49 51 6 Issue costs beginning of year (3) (3) 7 Amortization of Issue Costs 0 1 89 Effective Cost Rate 8.89% 8.89%1011 2007 5-year Term Intercompany Loan12 Liability beginning of year $200 $20013 Issue during year - - 14 Sinking fund payments - - 15 Average Capitalization 200 200 16 Annual Interest Expense 9 12 17 Issue costs beginning of year 2 2 18 Amortization of Issue Costs 1 1 1920 Effective Cost Rate 4.75% 6.39%2122 Total Actual Debt23 Total Average Capitalization 757 781 2425 Effective Cost Rate 7.80% 8.25%

pacific northern gas (n.e.) ltd....customer care 466 395 71 325 315 293 322 712 meter reading 187...

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