r ï - British Columbia Utilities Commission · Manager Regulatory Coordinator Customer IS...

Janet P. Kennedy Vice President, Regulatory Affairs & Gas Supply

Pacific Northern Gas Ltd. #950 - 1185 West Georgia Street Vancouver, BC V6E 4E6 Tel: (604) 691-5680 Fax: (604) 697-6210 Email: [email protected]

Via E-Mail December 13, 2013 B.C. Utilities Commission File No.: 4.2.7(2013) 6th Floor - 900 Howe Street Vancouver, B.C. V6Z 2N3 Attention: Erica M. Hamilton Commission Secretary Dear Ms. Hamilton: Re: Pacific Northern Gas Ltd. (PNG)

PNG-West Division 2014 Revenue Requirements Application Submission of Supplemental Information

In connection with above reference proceeding, PNG is submitting the accompanying zipped Excel files containing an electronic copy of the financial schedules previously submitted in support of the 2014 Revenue Requirements Application. In addition, PNG is also submitting electronic PDF copies of the following documents as background information to the 2014 Revenue Requirements Application:

• Organizational Chart • Uniform Code of Accounts • 2012 Annual Report to the BCUC • 2012 Shared Services Study • 2010 Overhead Capitalization Study • 2009 Depreciation Study

Please direct any questions regarding the application to my attention. Yours truly, J.P. Kennedy cc. Eugene Kung (BCPIAC) – BCPSO

James Wightman (Econalysis Consulting) – BCPSO Carolyn MacEachern (Young Anderson) – Peace River Regional District

B-3

markhuds

PNG WEST 2014 REVENUE REQUIREMENTS

Pacific Northern Gas Ltd.Executive Organization Chart

Executive Assistant

President

Vice President, Finance Vice President, RegulatoryAffairs and Gas Supplyand Business Development

and Corporate Secretary

General ManagerOperations

November 2013

Resources & GovernmentRelations

Vice President, Human

12/11/2013

FOR INTERNAL USE ONLY

(110)

(4) (11) (1)

(1) (5) (0) (0) (2)

VP Human Resources& Government Relations

Financial Analyst Receptionist

Manager Commercial Manager IT Payroll / Benefits

AdministratorSystems and Controls Corporate Accounting Reporting & Taxation AdministratorSenior Regulatory Analyst Banner Billing Analyst Manager Financial Manager Manager Financial Senior NetworkSenior Network

Business Development Financial PlanningAffairs & Special Projects Planning & Development & Administrator

Manager Regulatory Coordinator Customer IS Controller Manager Financial

VP Regulatory Affairs VP Finance andand Gas Supply Business Development

Pacific Northern Gas Ltd.Vancouver Head Office

November 2013

PresidentExecutive Assistant

12/11/2013

FOR INTERNAL USE ONLY

(88)

(15) (0) (12) (5) (0) (13) (6) (2)

Lands & ROW 310 Assessment & Taxes 510Area Manager 1 Marketing 320CST 2 Safety & Training 520 CAD/GIS Technician

Area Manager 1CST 2

Area Manager 1CST 2CST 1

Area Manager 1CST 2CST 2CST 2

Area Manager 1CST 2

Area Manager 1CST 2

Notes:• Field Managers - Non Union• Department and Budget Center Code• CST = Customer Service Technician (Gas Fitter)• CSR = Customer Service Representative• S&S = Sales & Service (27)• O&C = Operations & Construction• Msmt = Measurement• (##) = Number Direct & Indirect Reports

(8)

931

Meter Reader 1

Pacific Northern Gas Ltd.NE Field Operations

Area Manager 1CST 2

Utilityman 2

CST 3CST 2

Fort St John Msmt

Fort St John S&S

Comp Stn OperComp Stn Oper

Utilityman 2Utilityman 2

CST 2


CST 4

Sr Meas Tech

951

Dawson Creek O&C 931Utilityman 1Utilityman 2

Utilityman 1Fort St John O&C

Manager of Operations, NEFort St John

Manager, Comm Relations & AdminTerrace

Manager, Operations AccountingTerrace

AccountingAccountant

Pacific Northern Gas Ltd.West Field Operations

General Manager, OperaitonsTerrace

November 2013

Engineering610

Craig SearsPNG West & NE

410 810

Manager, Engineering & Spec ProjectsTerrace

Burns Lake O&CField DraftspersonSr. Meas. Tech

Manager, Construction & MaintenanceTerrace

Comp Stn Op/Mech

Summit Lake

Sr. Warehouseman

Corrosion 730Sr. Corrosion Tech


Welder 2

961Tumbler Ridge Plant

Compression 740

Sr Comp Stn OpUtilityman 2Welder 2

Equipment Op 1Welder 2

720

Manager, Technical ServicesTerrace

Measurement 710

Meas. Tech 1

Utilityman 1 (Vhf)

620

Warehouse

Terrace O&C

Welder 1Utilityman 2Utilityman 2

Equipment Op 1

420CSR

Meter Records

Accts PayableAccts PayableAccts Payable

Payroll

CSRCSRCSR

CSRCSRCSRCSR

CSRCSR

Customer Care

Coordinator, Marketing & LandsTerrace

Vanderhoof S&S

Burns Lake S&S

210

220

Manager, Customer ServiceTerrace

Utilityman 3

CSR

Manager, Customer CareTerrace

250

260

Kitimat S&S

Prince Rupert

230

240

Smithers S&S

Terrace S&S

Meter Reader 1

Dawson Creek S&S

Dawson Creek Msmt 931Msmt Tech 1

Mgr Const./Mtnce PNG NEDawson Creek

951

951

Area Manager 1CST 2

CST 2Meter Reader 1Meter Reader 1Meter Reader 1

12/11/2013

Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.

BCUC Code of Accounts

BCUC AccountCode Description

GENERAL ACCOUNTS - ASSETS

100 Gas Plant in Service101 Gas Plant Leased to Others102 Gas Plant Held for Future Use103 Retirement Work in Progress104 Fixed Asset Purchases - Clearing Account105 Accumulated Depreciation - Gas Plant106 Accumulated Amortization - Gas Plant109 AD Conversion Clearing110 Intangible Plant111 Accumulated Depreciation - Intangible Plant112 Accumulated Amortization - Intangible Plant114 Intangible Fixed Asset Purchases - Clearing Account115 Gas Plant under Construction116 Other Plant under Construction117 Utility Plant under Construction

LONG TERM INVESTMENTS

120 Investments in Affiliated Companies121 Other Long Term Investments122 Sinking Funds123 Miscellaneous Funds124 Company Long Term Debt Owed125 Second Mortgages Receivable126 Allowance for Loss in Value or Investments

CURRENT AND ACCRUED ASSETS

130 Cash131 Special Deposits132 Temporary Cash Investments140 Accounts Receivable - Trade141 Accounts Receivable - Other142 Accounts Receivable - Affiliated Companies145 Allowance for Doubtful Accounts147 Interest and Dividends Receivable150 Material and Supplies - Gas151 Material and Supplies - Other152 Gas Stored Underground - Available for Sale153 Transmission Line Pack Gas160 Prepayments162 Other Current and Accrued Assets163 Future Income Tax - Current165 Derivative Financial Instruments - current

DEFERRED CHARGES

G:\FINANCE\2014\Narrative, Correspondence, Orders\Application Narrative\Documents for Website\Chart of Accounts[BCUC Account Codes] 12/12/2013




170 Unamortized Debt Discount and Expense171 Preliminary Survey and Investigation Charges173 Other Work in Progress175 Unamortized Conversion Expense176 Public Improvements177 Capital Stock Expense178 Organization Expense179 Other Defered Charges

FUTURE INCOME TAX - LONG TERM

180 Future Income Tax - Long Term

REGULATED ASSET - LONG TERM

182 Regulated Asset - Long Term

DERIVATIVE FINANCIAL INSTRUMENTS

185 Derivative Financial Instruments

GOODWILL

190 Goodwill

GENERAL ACCOUNTS - CAPITALSURPLUS AND LIABILITIES

CAPITAL STOCK AND SURPLUS

200 Preferred Stock205 Common Stock206 Partners' Capital210 Contributed Surplus211 Contributions and Grants212 Retained Earnings213 Other Comprehensive Income214 Non-controlling interest215 Appropriated Retained Earnings216 Excess of Redetermined value of Plant over Depreciated Cost

LONG TERM DEBT

220 Long Term Debt249 Other Long Term Debt

CURRENT AND ACCRUED LIABILITIES





250 Loans and Notes Payable251 Accounts Payable and Accrued252 Accounts Payable - Affiliated Companies253 Dividends Payable254 Customers' Security Deposits255 Customers' Security Advances for Construction256 Taxes Accrued257 Interest Payable and Accrued258 Long Term Debt Due Within One Year259 Other Current and Accrued Liabilities263 Future Income Taxes - Current265 Derivative Financial Instruments - Current

DEFFERED CREDITS

270 Unamortized Debt Premium271 Unearned Finance Charges on Customers'

Accounts Receivable (Credit)275 Gas Cost and Maintenance Equalization276 Accumulated Tax Reductions Applicable to

Future Years279 Other Deferred Credits281 Non-Regulated Deferred Credits

FUTURE INCOME TAX - LONG TERM

280 Future Income Taxes - Long Term

DERIVATIVE FINANCIAL INSTRUMENTS

285 Derivative Financial Instruments

RESERVES

290 Insurance Reserves291 Welfare and Pension Reserves292 Injuries and Damages Reserves293 Other Reserves





GENERAL ACCOUNTS - INCOME

300 Operating Revenue301 Operating Expense302 Maintenance Expense303 Depreciation304 Amortization305 Municipal and Other Taxes306 Income Taxes307 Non-Controlling Interest308 Rent for Gas Plant Leased from Others310 Revenue from Other Plant311 Expense of Other Plant312 Non-Operating Revenue313 Non-Operating Expense314 Income from Investments315 Income from Investments in Affiliated Companies316 Income from Sinking and other Funds317 Gain on Foreign Exchange319 Other Income320 Interest on Long Term Debt321 Amortization of Debt Discount, Premium and Expense322 Interest on Amounts Due Affiliated Companies323 Other Interest Expense324 Allowance for Fund Used During Construction325 Loss on Foreign Exchange329 Other Income Deductions330 Appropriations of Net Income331 Extraordinary Income332 Extraordinary Deductions

GENERAL ACCOUNTS - RETAINED EARNINGS

350 Balance Transferred from Income351 Appropriations of Retained Earnings357 Dividend Appropriations359 Adjustments to Retained Earnings

DETAIL ACCOUNTS - PLANT

INTANGIBLE PLANT

401 Franchise and Consents402 Other Intangible Plant

NATURAL GAS PRODUCTION PLANT





403 Gas Lands404 Gas Leaseholds405 Gas Rights406 Producing Gas Wells - Well Drilling407 Producing Gas Wells - Well Equipment408 Gas Well Structures409 Other Natural gas Production Equipment

NATURAL GAS GATERING PLANT

410 Land411 Land Rights412 Compressor Structures and Improvements413 Measuring and Regulating Structures and Improvements414 Other Structures and Improvements415 Gathering Lines416 Compressor Equipment417 Measuring and Regulating Equipment418 Pruification Equipment419 Other Natural Gas Gathering Equipment

PRODUCTS EXTRACTION PLANT

420 Land421 Land Rights422 Structures and Improvements423 Extraction Equipment424 Products Storage Equipment425 Pipe Lines426 Compressor Equipment427 Measuring and Regulating Equipment428 Purification Equipment429 Other Products Extraction Equipment

HYDROELECTRIC POWER PLANT

430 Land431 Intangible - Land Rights432 Structures and Improvements433 Reserved for Hydroelectric Power plant assets434 Reserved for Hydroelectric Power plant assets436 Reserved for Hydroelectric Power plant assets437 Reserved for Hydroelectric Power plant assets438 Reserved for Hydroelectric Power plant assets439 Other Hydroelectric Equipment

LOCAL STORAGE PLANT





440 Land441 Land Rights442 Structures and Improvements443 Gas Holders449 Other Local Storage Equipment

TRANSMISSION PLANT

450 Land451 Land Rights452 Structures and Improvements453 Wells454 Well Equipment455 Field Lines456 Compressor Equipment457 Measuring and Regulating Equipment458 Base Pressure Gas459 Other Underground Storage Equipment

TRANSMISSION PLANT

460 Land461 Land Rights462 Compressor Structures and Improvements463 Measuring and Regulating Structures and Improvements464 Other Structures and Improvements465 Mains466 Compressor Equipment467 Measuring and Regulating Equipment468 Communication Structures and Equipment469 Other Transmission Equipment

DISTRIBUTION PLANT

470 Land471 Land Rights472 Structures and Improvements473 Services474 House Regulators and Meter Installations475 Mains476 Compressor Equipment477 Measuring and Regulating Equipment478 Meters479 Other Distribution Equipment

GENERAL PLANT

480 Land





481 Land Rights482 Structures and Improvements483 Office Furniture and Equipment484 Transportation Equipment485 Heavy Work Equipment486 Tools and Workk Equipment487 Computer Equipment488 Communication Structures and Equipment489 Other General Equipment490 Intangible Communication Structures and Equipment

UNDISTRIBUTED PLANT

496 Unclassified Plant497 Allowance for Fund Used During Construction498 Overhead Charged to Construction

DETAIL ACCOUNTS - OPERATING REVENUE

SALES OF GAS

500 Canadian Sales510 Foreign Sales520 Residential Sales521 Commercial Sales522 Industrial Sales523 Transportation Sales524 Interdepartmental Sales526 Deferred Revenue from Sales529 Other Sales

HYDROELECTRIC REVENUE

530 Hydroelectric Revenue from Sales

OTHER OPERATING REVENUE

550 Sales of Products Extracted from Gas551 Revenue from Natural Gas Processed by Others560 Forfeited Discounts - Penalties561 Revenue from Service Work570 Transportation and Storage of Gas of Others575 Rent from Gas Plant576 Rent from Company Equipment on Customers' Premises579 Miscellaneous Operating Revenue580 Customer Contributions in Aid of Construction

DETAIL ACCOUNTS - OPERATING EXPENSES





EXPLORATION AND DEVELOPMENT - OPERATION

600 Supervision602 Delay Rentals603 Non-Productive well Drilling604 Abandoned Leases609 Other Exploration and Development Operation

NATURAL GAS PRODUCTION AND GATHERING - OPERATION

610 Supervision611 Royalties612 Gathering of gas by Others614 Gas Wells615 Pipe Lines616 Compressor617 Measuring and Regulating618 Purification619 Other Natural Gas Production and Gathering Operation

PRODUCTS EXTRACTION - OPERATION

620 Supervision621 Extraction and Refining622 Gas Processing by Others

GAS SUPPLY - OPERATION

623 Gas Purchases - Residential624 Gas Purchases - Commercial625 Gas Purchases - Industrial626 Exchange Gas627 Gas Withdrawn from Underground Storage628 Gas Delivered to Underground Storage (Credit)629 Gas Used (Credit)

MANUFACTURED GAS PRODUCTION - OPERATION

630 Supervision631 Fuel and Fuel Handling632 Manufacture633 Manufacture - Liquified Petroleum Gas634 Gas Holders - Manufacturing638 Purifiction639 Other Manufactured gas Prodcution Operation

LOCAL STORAGE - OPERATION





640 Supervision644 Gas Holders - Storage649 Other Local Storage Operation

UNDERGROUND STORAGE - OPERATION

650 Supervision651 Exploration and Development653 Wells654 Gas Losses655 Field Lines656 Compressor657 Measuring and Regulating658 Purification659 Other Underground Storage Operation

TRANSMISSION OPERATION

660 Supervision663 Transportation of Gas by Others664 Communication665 Pipe Lines666 Compressor667 Measuring and Regulating669 Other Transmission Operation

DISTRIBUTION - OPERATION

670 Supervision671 Load Dispatching673 Removing and Resetting Meters and House Regulators674 Service on Customers' Premises675 Mains and Services676 Compressor677 Measuring and Regulating679 Other Distribution Operation

GENERAL - OPERATION

684 Communication685 System Operation and Engineering687 Training688 Other General Operationg689 General Operations Transferred (Credit)

DISTRIBUTION SALE PROMOTION - OPERATION





700 Supervision701 Advertising702 Demonstrtion and Selling Expense703 Revenue from Merchandising, Jovving and Contract Work704 Expense from Merchandising, Jovving and Contract Work709 Other Sales Promotion Operation

DISTRIBUTION CUSTOMER ACCOUNTING - OPERATION

710 Supervision711 Customers' Contracts and Orders712 Meter Reading and Bill Delivery713 Customers' Bililng and Accounting714 Credit and Collection718 Uncollectible Accounts719 Other Customer Accounting Operations

ADMINISTRATIVE AND GENERAL - OPERATION

721 Administrative Expense722 Special Services723 Insurance724 Injuries and Damages725 Employee Benefits728 Other Administrative and General Expenses729 Administrative and General Expenses Transferred (Credit)

NON-REGULATED BUSINESS ACTIVITIES

750 Other Non-Regulated Business751 Renewable Power Development752 Renewable Power Projects

DETAIL ACCOUNTS - MAINTENANCE EXPENSES

NATURAL GAS PRODUCTION AND GATHERING - MTCE.

810 Supervision814 Gas Wells815 Pipe Lines816 Compressor817 Measuring and Regulating818 Purification819 Other Natural Gas Production and Gathering Maintenance

PRODUCTS EXTRACTION MAINTENANCE

820 Supervision





821 Extraction and Refining

MANUFACTURED GAS PRODUCTION - MAINTENANCE

830 Supervision832 Structures and Improvements834 Gas Hoeders - Manufacturing838 Purification839 Other Manufactured Gas Production Maintenance

LOCAL STORAGE - MAINTENANCE

840 Supervision842 Structures and Improvements844 Gas Holders - Storage849 Other Local Storage Maintenance

UNDERGROUND STORAGE - MAINTENANCE

850 Supervision853 Wells855 Field Lines856 Compressor857 Measuring and Regulating858 Purificiation859 Other Underground Storage Maintenance

TRANSMISSION - MAINTENANCE

860 Supervision864 Communication865 Pipe Lines866 Compressor867 Measuring and Regulating869 Oher Transmission Maintenance

DISTRIBUTION - MAINTENANCE

870 Supervision872 Structures and Improvements874 Equipment on Customers' Premises875 Mains and Sdrvices876 Compressor877 Measuring and Regulating878 Meters879 Other Distribution Maintenance

GENERAL MAINTENANCE





884 Communication885 System Maintenance and Engineering888 Other General Maintenance889 General Maintenance Transferred (Credit)

CLEARING ACCOUNTS

900 Warehouse Expense901 Transportation Equipment Expense902 Heavy Work Equipment Expense903 Aircraft Expense904 Printing and Reproduction Expense

UNIT ACCOUNTS

920 Residential Sales - Deliveries (GJ's)921 Commercial Sales - Deliveries (GJ's)922 Industrial Sales - Deliveries (GJ's)923 Transport Services - Deliveries (GJ's)

950 Company Use of Gas - Deliveries (GJ's)

970 Residential Sales - Customer Count971 Commercial Sales - Customer Count972 Industrial Sales - Customer Count973 Transport Services - Customer Count

980 Degree Days


Evaluation of the Revised Shared Services Cost Allocation Model and the Analysis of the Cost of a Standalone Customer Care Centre for PNG(NE) Prepared by: Pacific Northern Gas Ltd.

November 30, 2012

2

Table of Contents

1.0 Summary of Findings .................................................................................... 3

2.0 Purpose of the Report ................................................................................ 10

3.0 Background ................................................................................................ 14

4.0 KPMG Evaluation Approach ....................................................................... 15

5.0 KPMG Findings .......................................................................................... 18

Appendix A – PNG’s Shared Service Cost Allocation Principles .................................. 34

Appendix B – Summary of PNG’s Current Shared Service Cost Allocation Model and Proposed Changes Thereto ................................................................... 35

Appendix C – PNG Management’s Standalone Customer Care Centre Assessment .. 53

3

1.0 Summary of Findings

1.1 Overview

KPMG was retained by Pacific Northern Gas Ltd. to conduct an evaluation of Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd.’s (collectively “PNG” or the “Company”) revised 2012 shared services cost allocation model (a summary of PNG’s proposed model is included in Appendix B) for purposes of reporting to the British Columbia Utilities Commission (“the Commission”) as set forth in the negotiated settlement of PNG’s 2011 revenue requirements application. Specifically, KPMG assessed the shared costs (referred to in this report as “Cost Pools”) and related cost allocators (or “drivers”) that were utilized in the updated shared services cost allocation model to allocate shared service costs from Pacific Northern Gas Ltd. to Pacific Northern Gas (N.E.) Ltd. (“PNG(NE)”).

The Commission has also asked PNG to assess whether the Customer Care Centre services currently provided to PNG(NE) from PNG’s Terrace office could be provided more economically on a standalone basis from a dedicated Customer Care Centre located in the PNG(NE) service area. PNG has also engaged KPMG to review Management’s estimated annual operating and initial start-up costs (PNG’s estimated costs are included in Appendix C) of a dedicated Customer Care Centre located in the PNG(NE) service area of Fort St. John and conclude thereon.

1.2 Evaluation of PNG Shared Service Cost Allocation Model

KPMG assessed the shared service cost pools and cost allocators utilized in the Company’s revised shared services cost allocation model (outlined in Appendix B).

1.2.1 (i) PNG’s Cost Pool and Cost Allocator Principles

KPMG discussed with Management and reviewed PNG’s cost pool and cost allocator principles discussed in Appendix A to ensure they form a reasonable guide for PNG’s cost pool and cost allocator selection process. Assessed whether Appendix A principles represent appropriate principles for KPMG to assess PNG’s final selected cost pools and cost allocators against in its conclusions in this report, or if adjustments were required for our reporting purposes. 1.2.1 (ii) Cost Pools

KPMG reviewed the completeness of the identified shared cost pools through the following procedures noted in Section 4.0, which included:

Discussed and reviewed general ledger costs which were not allocated to a shared cost pool with managers to assess if related costs were incurred for the benefit of PNG(NE) and therefore should be allocated to a cost pool;

Reviewed shared cost pools, which included both labour and/or non-labour components, through discussions with Management and divisional personnel on the activities undertaken to see if other general ledger costs were associated with these existing shared cost pool amounts and should be included in these shared cost pools; and

Reviewed management and divisional personnel assigned to shared cost pools to ascertain if other individuals are associated with services benefiting PNG(NE) and should therefore also be included.

4

KPMG assessed the accuracy of the cost pools through the procedures noted in Section 4.0, which included:

For a sample of individuals in each shared cost pool, agreed their roles to job descriptions, employee organizational charts and time study results to time sheets;

Reconciled shared cost pool details to PNG’s 2012 budget figures from its Revenue Requirement Application, as updated on March 15, 2012;

KPMG discussed organizational changes with Management that may change shared cost pools and assessed if changes to shared cost pools were supported; and

KPMG assessed the final shared cost pools against PNG principles discussed in Appendix A.

1.2.1 (iii) Cost Allocators and Application

KPMG assessed the proposed cost pool allocators and their application by performing the procedures noted in Section 4.0, which included:

Compared the cost allocators to prior year cost allocators and discussed any changes with Management;

Compared proposed cost allocators to each of PNG established cost driver assessment principles disclosed in Appendix A and to other possible allocator(s) alternatives;

Assessed other possible allocator alternative(s); and

Re-performed allocations using the proposed allocators and discussed the resulting allocation with Management to ensure the PNG(NE) allocation was reasonable in nature and amount.

1.2.1.2 KPMG Conclusion

Based on the scope and the results of the above procedures and other procedures more fully described in Section 4.0:

KPMG is of the view that the shared cost pools and the cost allocator principles in Appendix A form a reasonable guide for PNG’s cost pool and cost allocator selection process and are appropriate principles for KPMG to assess PNG’s final selected cost pools and cost allocators.

KPMG is of the view that the final shared cost pools and cost allocators proposed for use in the PNG shared services cost allocation model meet the internal objectives and principles criteria established by PNG as detailed in Appendix A, and as a result form a reasonable and objective basis of cost allocation.

Table 1 below presents the final shared cost pools and cost allocators and the resulting cost allocation using the 2012 budget figures and a comparison to the previous cost pools and previously applied allocators.

5

Table 1 - Summary of Shared Cost Pools and Service Cost Allocators

Shared Service Cost Pool

Total $ Value of

Proposed Cost

Pool(1)

Proposed Cost

Allocator

Total $ Value of Proposed

Cost Pool Allocated to

NE Using Proposed

Allocators(1)

% of Proposed Cost Pool

Allocated to NE Using Proposed Allocators

(Prior allocation)

Explanation of Proposed Cost

Allocator Amendments

Are the proposed Cost Pools,

allocators and final allocation reasonable and consistent with

PNG’s allocation principles?

721 – Vancouver Administration

Labour component 3,227,072 Time-based 931,272 28.9%

(20.8%) Updated time study results Yes

Non- labour component 792,821

4,019,893

Composite Average

Allocator A(2) 251,616

31.7% (20.8%)

A composite average of

relevant allocators

Yes

711/713/714 – Terrace Customer Care Centre

Labour component

1,126,233

Time-based 554,169

49.2% (48.2%)

Updated time study results Yes

Non-labour component

158,232 1,284,465

Composite Average

Allocators B(2) 77,047

48.7% (48.2%)


relevant allocators

Yes

711/713/714 – Vancouver Billing Services (new)

Labour component

197,547

Customer Count 95,176

48.2%(3)

(-%)(3)

Updated customer count Yes


168,323 365,870

Customer Count 81,096

48.2%

(-%)(3)


685 – Terrace Management

Labour component

878,223

Time-based 324,064 36.9%



263,540

1,141,763

Composite Average


33.7% (-%)


relevant allocators

Yes

6


Total $ Value of

Proposed Cost

Pool(1)

Proposed Cost

Allocator



NE Using Proposed

Allocators(1)



(Prior allocation)






685 – Terrace Accounting (formerly Terrace Accounting/Warehouse)

Labour component

481,841

Time-based 204,282 42.4%



34,249 516,090

Composite Average


35.1% (23.9%)


relevant allocators

Yes

685 – Terrace Technical Services- Warehouse/ Corrosion (new)


205,246

Composite Average

Allocator C(2) 67,108

32.7%

(-%)(4)


relevant allocators

Yes

685 – Terrace Drafting


70,553 Composite Average


32.7% (48.2%)


relevant allocators

Yes

685 – Terrace Safety & Training (formerly Terrace Engineering)

Yes Non-labour component

87,427

Composite Average


32.7% (20.8%)


relevant allocators

728 – Vancouver Corporate Expenses

Yes Non-labour

component

519,588

Composite Average


32.7% (26.1%)


relevant allocators

7


Total $ Value of

Proposed Cost

Pool(1)

Proposed Cost

Allocator



NE Using Proposed

Allocators(1)



(Prior allocation)






713 – Vancouver Vertex Billing Services


946,986

Customer count 456,142

48.2% (48.2%)


722 – Vancouver Special Services


253,055

Composite Average


32.7% (32.5%)


relevant allocators

Yes

723 – Vancouver Insurance


810,437

Insurance Composite

101,665 12.5%

(12.5%)

Updated insurance composite

Yes

10,221,373 3,548,883 (3,016,436)

34.7% (30.5%)

(1) The cost pool figures are derived from PNG’s 2012 revenue requirements application, as updated on March 15, 2012 (2) Management elected to use an average or composite allocator for the non-labour component as the chosen allocators influence

this cost pool component. Composite Average Allocator A - this is an average of allocators including Time-Based, Customer Count, Employee Count and

Rate Base allocators which influence the cost pool (See Appendix B.4.4 Composite Allocators)

Composite Average Allocator B - this is an average of allocators including Time-Based and Customer Count Allocators which influence the cost pool (See Appendix B.4.4 Composite Allocators)

. Composite Average Allocator C - this is an average of allocators including Customer Count, Employee Count and Rate Base allocators which influence the cost pool. (See Appendix B.4.4 Composite Allocators)

(3) Included with 711/713/714 – Terrace Customer Care in prior years. The labour component was allocated based upon customer count as it influenced the level of labour costs significantly. Billing matters are general in nature and are not specific to PNG(NE) and as a result time study results were not available or relevant.

(4) Included with 685 – Terrace Accounting in prior years.

8

1.3 Evaluation of Proposed Standalone Customer Care Centre

1.3.1 Standalone Customer Care Centre Costs

PNG asked KPMG to review Management’s estimated annual operating and initial start-up costs for a dedicated Customer Care Centre located in the PNG(NE) service area of Fort St. John and conclude thereon. As directed in the negotiated settlement of PNG’s 2011 revenue requirements application, PNG is required to perform an assessment as to whether the Customer Care Centre services, currently provided to PNG(NE) from PNG’s Terrace office, could be provided more economically on a standalone basis from a dedicated Customer Care Centre located in the PNG(NE) service area.

These cost estimates were developed by PNG Management using vendor or agent quotes and/or estimates developed by experienced and knowledgeable PNG personnel that have extensive industry experience and/or work within PNG’s existing customer care operation.

PNG’s key assumptions and centre requirements included in cost estimates:

Fort St. John is the most viable location, as one of PNG’s existing main operating offices is already located in Fort St. John, giving PNG knowledge and experience and operational synergies to establish a standalone call centre in this city; no other location was viewed by Management as appropriate.

The existing Terrace call centre staff would likely not relocate to the proposed Fort St. John location. All standalone call centre staff will be newly hired, including 7 customer service representatives (“CSR”) and 1 manager;

Existing Terrace CSRs and Managers would train newly hired staff;

Five redundant Terrace CSRs would receive severance pay;

Certain furniture and fixtures and other property and equipment (capital items) from its existing call centre operations would be transferred to the new proposed facility; and

It is more cost effective and practical to lease office space than to finance an expansion or purchase. The estimated lease space required is 1,900 square feet.

The following tables provide a summary of the final estimates of annual operating and initial start-up costs of establishing a standalone customer call centre in Fort St. John.

Table 2 - Summary of Annual Operating Costs of Standalone Customer Care Centre

Type of Costs Estimated Annual Standalone Costs for Customer Care Centre in NE Region

General and Administrative $ 17,400 Training 4,200 Customer Contracts and Orders 16,750 Customer Billing and Accounting 13,700 Credit and Collections 19,000 Office Equipment Maintenance 2,500 Office Lease and Utilities 57,374 Salary and Benefits 703,597 Total Annual Expense $ 834,521

9

Table 3 - Summary of Start-up Costs of Standalone Customer Care Centre

Type of Cost Estimated Start-up Costs of Standalone

Customer Care Centre in NE Region

Initial Training $ 230,475 Severance 150,000 Recruitment Costs 76,000 Capital Expenditures- Equipment and Fixtures 85,225 Total Startup costs $ 541,700(1)

(1) This estimate does not include the cost to purchase office space as leasing of office space was determined to be more economical and practical.

KPMG performed the following procedures (and others more fully described in Section 4.0) in assessing the reasonableness of the above summaries of aggregated annual operating and start-up costs of the proposed standalone Customer Care Centre in Fort St. John area, including the reasonableness of the underlying assumptions and source data used:

Assessed the completeness and breadth of costs captured and assumptions by comparing those to PNG’s existing customer care centre costs in Terrace and also comparing them to other customer care assessment projects which KPMG has been involved with;

Discussed with Management personnel regarding the costs proposed, challenging assumptions used and the basis for each line item of annual and start-up costs; and

Assessed the accuracy of cost estimates by agreeing a judgmental sample of the costs to vendor invoices for its existing care centre, vendor quotes, labour contract rates and terms, and payroll records for existing care centre staff.

1.3.2 KPMG Conclusion

Based on the results of our procedures as more fully described in Section 4.0, KPMG is of the view that the estimated summary of annual operating and start-up costs for the proposed standalone customer care centre in Fort St. John to be within a reasonable range, after reflecting certain immaterial adjustments proposed by KPMG based upon its findings, per Section 5.8.

10

2.0 Purpose of the Report

2.1 Purpose

KPMG was retained by PNG to conduct an evaluation of its revised 2012 shared services cost allocation model.

Specifically, KPMG was engaged to assess:

PNG’s cost pool and cost allocator principles discussed in Appendix A to ensure they form a reasonable guide for PNG’s cost pool and cost allocator selection process and whether Appendix A principles represent appropriate principles for KPMG to assess PNG’s final selected cost pools and cost allocators against in its conclusions in this report, or if adjustments were required to the principles for our reporting purposes;

Whether the shared cost pools met PNG’s basic cost pool assessment criteria in A.1 of Appendix A and therefore deemed relevant and appropriate for allocations; and

Whether the utilized cost allocators related to the shared service cost pools met PNG’s cost driver assessment principles and therefore deemed to be reasonable to use as a basis for allocation.

In addition, PNG requested that KPMG review Management’s estimates of annual operating and start-up costs of a standalone basis from a dedicated Customer Care Centre located in the PNG(NE) service area of Fort St. John.

11

2.2 Report Structure

The Tables below describe the sections and appendices in this report.

Report Body Section Descriptions

Section Description

1.0:Summary of Findings Includes a brief discussion of KPMG’s approach and summary of findings.

2.0: Purpose of Report Outlines the structure of the report and provides a brief explanation of each section and outlines the nature of the KPMG engagement.

3.0: Background Provides background on the reasons why PNG assessed the shared service cost allocation methodology and also why it performed an economic and related qualitative assessment of having a standalone customer care centre in the PNG(NE) service area.

4.0: KPMG approach and specified procedures performed

Provides an explanation of KPMG’s approach and procedures performed to assess PNG’s revised shared service cost allocation methodology, and other assumptions used by KPMG during its analysis and resulting limitations. Provides an explanation of KPMG’s approach and procedures performed to assess PNG’s estimated cost of providing a standalone customer care centre in the PNG(NE) service area. The scope of the above evaluation is pursuant to the terms of the engagement letter between KPMG and PNG.

5.0: KPMG Findings from the specified procedures performed and resulting material recommendations

Provides KPMG’s findings from the procedures it performed to assess the shared service cost allocation methodology. It also provides KPMG’s significant recommended changes resulting from its findings and if PNG implemented these recommendations. Provides KPMG’s findings from procedures performed to assess the cost of a proposed standalone service centre in the PNG(NE) service area. It also provides KPMG’s significant recommended changes resulting from its findings and if PNG implemented these recommendations. The final PNG revised allocation model and final standalone call centre costs is presented with KPMG’s final assessment conclusions.

Report Appendices Section Descriptions

Appendix Description

A: PNG’s Shared Services Cost Allocation Principles

Contains a detailed description of the principles behind PNG’s shared service cost allocations.

B. Summary of PNG’s current Shared Service Cost Allocation Model and its proposed changes

Copy of PNG’s high level summary of the current shared service cost allocation methodology, a summary of PNG’s Management’s assessment process and the resulting, proposed, changes to be implemented as part of the 2013 revenue requirements application.

C Summary costs of a proposed standalone customer care centre in the PNG(NE) service area and PNG Management’s assessment

Copy of PNG’s high level summary of estimated annual and initial start-up costs for a proposed customer care centre in PNG(NE) service area and Management’s assessment process and related conclusions.

12

2.3 Limitations

2.3.1 Scope of review

In preparation of its report, KPMG reviewed and has relied upon the following documents and information:

Historical (2012) Cost Allocation Model Documentation

Shared Services General Ledger Detail - Budget Centre Summary

2012 Preliminary Rate Application Benefit Load Factors

PNG RFP for Shared Services Study (March 2012)

PNG Organizational Charts

Time Study Results Excel Spreadsheets and Sample of Supporting Time Sheets

Payroll and Other Information Supporting Customer Count, Employee Count and Rate Base Non-labour Cost Allocator Percentages

PNG Standalone Customer Care Centre Cost Estimate Excel Spreadsheets

Payroll and Other Information Support for PNG Cost Estimates

Third Party Lease Cost Estimates for Fort St. John

Various Discussions and Meetings with PNG Management and Personnel

2.3.2 Restrictions on distribution

KPMG’s report is confidential and is solely for the use of PNG in these specifically identified matters. KPMG understands that its report may be used by PNG in its 2013 revenue requirements application to the Commission. KPMG’s report shall not be used or published for any other purpose other than the purpose outlined above, without KPMG’s prior written consent in each and every instance. KPMG will not assume any responsibility or liability for any costs, damages, losses, liabilities or expenses suffered by PNG and its subsidiaries as a result of the circulation, publication, reproduction, use or reliance upon its report. In addition, KPMG will not assume any responsibility or liability for any costs, damages, losses, liabilities or expenses incurred by anyone else as a result of the circulation, publication, reproduction, use or reliance upon its report.

2.3.3 KPMG engagement limitations

Our engagement is to assess and comment on the shared service cost allocation methodology based upon the results of procedures outlined in Section 4.0 of this report.

Our engagement is also to assess and comment on the aggregate cost estimates of a standalone call centre facility in the PNG(NE) service area, including reasonableness of assumptions and source data, based upon the results of procedures outlined in Section 4.0 of this report.

13

This evaluation does not constitute an audit of the shared cost allocation methodology, including associated cost pools and cost allocators, or of the cost estimates of a standalone call centre. Accordingly, we do not express such an opinion on such matters. For avoidance of doubt, KPMG has neither audited nor reviewed the underlying shared service cost pools, the data that underpins the PNG cost driver allocators that form the basis of the allocations per PNG’s report, and the cost estimates of the standalone call centre in this report.

PNG prepared the proposed shared service cost allocations using 2012 budget figures from PNG’s revenue requirement application, as updated on March 15, 2012. Our findings and conclusions are therefore limited accordingly and do not assess the reasonableness of such budgetary amounts.

14

3.0 Background

PNG, as the parent company of PNG(NE), provides a number of administrative, accounting and regulatory and other reporting services to PNG(NE). The services are provided for PNG(NE) by PNG employees located in PNG’s Vancouver head office and in its Terrace regional office. PNG allocates its costs for such shared services using a number of different cost allocators, including allocators based upon relative time, relative number of customers, relative number of employees and relative rate base.

PNG itself became a subsidiary of AltaGas Ltd., a publically listed entity, on December 20, 2011. Management fees charged to PNG by AltaGas Ltd. are also included in a shared service cost pool that is allocated to PNG(NE).

The need for a new shared service cost allocation assessment was set forth in the negotiated settlement of PNG’s 2011 revenue requirements application. In the settlement, the Commission noted that the basis of the calculation of the shared service costs had not been reviewed by a third party for many years, in particular the time study allocator has not been reviewed in detail since completion of an internal study by PNG in 2003.

As such, the Commission ordered that PNG submit a Cost Allocators and Level of Shared Service Cost Recovery standalone application in Fall 2012 based on a shared service cost study prepared by a third party consultant. This study is to incorporate a time study prepared by PNG for the period of July 2011 to July 2012, which collects data on time spent by PNG-West personnel on PNG(NE) matters.

In addition, the shared service cost study is also to include an analysis of whether Customer Care Centre services provided to PNG(NE) from the PNG-West Terrace office could be provided more economically on a standalone basis from a dedicated Customer Care Centre in the PNG(NE) service area.

On September 19, 2012, PNG sent a request to the Commission asking for permission to incorporate and include the Cost Allocators and Level of Shared Service Cost Recovery application as part of its 2013 revenue requirements application, rather that filing a separate standalone application. Approval for this request was granted by the Commission on October 19, 2012.

15

4.0 KPMG Evaluation Approach

This section summarizes KPMG’s approach to conducting our evaluation of PNG’s updated shared service cost allocation methodology for 2012 and its cost estimates of a standalone customer care centre in Fort St. John.

Our work plan incorporated the following phases:

Phase 1: Launch. In this phase, KPMG met with PNG Management to obtain PNG Management’s initial estimates of cost pools and allocators and standalone care centre costs, identified primary PNG contacts and obtained other relevant information available from PNG.

Phase 2: Cost Pools. In this phase, KPMG performed the following:

Reviewed existing PNG cost allocation methodology documentation, including current shared cost pools, process documentation, Commission correspondence, policy documentation, and peer group models to the extent possible;

Reviewed the historic cost allocation model to gain an understanding of the cost drivers and the cost allocation process;

Obtained and discussed with PNG Management its guiding principles for identifying appropriate shared cost pools. KPMG assessed the final shared cost pools against PNG cost pool principles discussed in Appendix A;

Obtained details of PNG Management’s proposed shared cost pools. Identified and reviewed and discussed the amounts and activities within shared cost pools prepared by PNG to determine whether the shared cost pools should be adjusted. As part of this procedure we reviewed job descriptions of individuals within the shared cost pools and conducted interviews with relevant PNG Management and staff;

Discussed and reviewed general ledger budget costs which were not allocated to a cost pool with management and divisional managers to assess if related costs were incurred for the benefit of PNG(NE) and should be included in the cost pools;

Reviewed shared cost pools, including labour and/or non-labour components, and discussed and reviewed costs to see if other general ledger costs were missing as they were associated with these activities and therefore should be included in these shared cost pools;

Reviewed personnel assigned to shared cost pools and enquired of management if other individuals are associated with services benefiting PNG(NE); and

KPMG discussed organizational changes with management that may change shared cost pools and assessed if changes to shared cost pools were made in response and were supported.

Phase 3: Review Allocation Methodologies and Cost Drivers. In this phase, KPMG performed the following:

Compared the cost allocators to historic cost allocators;

Evaluated the appropriateness of each cost driver for allocation of cost pool expenditures against internal cost driver principles (included in Appendix A), including identification of options (where applicable), and their pros and cons;

Reviewed the information collected from PNG’s Time Study, and:

16

(i) assessed the appropriateness of people included;

(ii) assessed the quality of the information collected;

(iii) assessed how the results were allocated to each cost pool with a labour component;

(iv) assessed the appropriateness of the Time Study as an allocation driver for the labour component of cost pools and in certain instances, the non-labour component of cost pools;

(v) assessed the method that PNG Management utilized to determine the employee benefit expense load as part of the allocation of labour costs to cost pools and tested certain data on a sample basis;

(vi) discussed with Management new cost drivers for non-labour related components of shared cost pools, the pros and cons of the recommended changes; and

(vii) assessed Management’s final cost drivers and assess Management’s resulting revised allocations for reasonableness.

Phase 4: Validate cost pools and cost allocators and methodology. In this phase, KPMG performed the following:

Reconciled cost pools details to PNG’s 2012 budget figures from its Revenue Requirement Application, as updated on March 15, 2012

For a sample of individuals in each cost pools, agree their roles to job descriptions, employee organizational charts and time study results to time sheets;

Validated the mathematical accuracy of cost driver allocations and ensured that the drivers are consistent with the drivers noted in Phase 3;

Checked that any recommended changes by KPMG to the cost pools and cost drivers are appropriately implemented; and

Checked the mathematical accuracy of the final updated allocation model. Re-performed allocations using the allocators and discussed the resulting allocation with Management to ensure the PNG(NE) allocation was reasonable in nature and amount.

Phase 5: Assessment of Standalone of Customer Care Centre for PNG(NE). In this phase, KPMG performed the following:

Obtained Management’s initial summary of annual operation costs and initial start-up costs and ensured that the summary total and spreadsheet formulas are mathematically correct;

Reviewed the assumptions applied underlying the cost estimates for reasonableness;

Reviewed the aggregated costs allocated to PNG(NE) relating to the Customer Care Centre under the current structure;

Reviewed the aggregated costs allocated to PNG(NE) relating to the Customer Care Centre under the newly proposed standalone care centre;

Assessed the costs estimated for a standalone Customer Care Centre in Fort St. John, including assumptions behind the costs;

17

Assessed the completeness and breadth of costs captured and assumptions made by comparing those to PNG’s existing customer care centre costs incurred at PNG’s Terrace Office, comparing them to other customer care assessment projects which KPMG has been involved with; and

Assessed the accuracy of cost estimates by agreeing a judgmental sample of the annual and start-up costs to vendor invoices for its existing care centre, vendor quotes, labour contract rates and terms, payroll records for existing care centre staff.

Phase 6: Prepared report. In this phase, KPMG prepared this report to summarize the results of the evaluation.

18

5.0 KPMG Findings

5.1 Summary

KPMG is of the view that the proposed cost pools are relevant and appropriate and the cost allocators used in the proposed shared services cost allocation model meet the internal objectives and principles criteria established by PNG, and form a reasonable and objective basis of allocation. The proposed methodology is consistent with the guiding principles of PNG in Appendix A

KPMG finds that PNG’s estimate of annual operating and start-up costs of a standalone call centre in Fort St. John to be within a reasonable range based upon the results of the procedures it performed.

5.2 Procedures and Findings related to the Shared Cost Pools, Cost Allocators and cost allocation methodology

KPMG preformed the following procedures in assessing the shared cost pools, cost allocators and cost allocation methodology prepared by PNG management (included in Appendix B). The results and findings of these assessment procedures and impact to the final results reported by PNG, if any, are also described.

Procedure Findings (see Table 2)

5.2.1 Cost Pools

1. Obtained existing PNG cost allocation methodology documentation, including current shared cost pools, process documentation, Commission correspondence, and policy documentation.

Completed, providing background information for balance of procedures.

2. Reviewed the historic and current proposed cost allocation model to gain an understanding of the cost drivers and the cost allocation process.

Completed, providing background information for balance of procedures.

3. Obtained and discussed with PNG Management its guiding principles (Appendix A) for identifying appropriate shared cost pools.

Completed. KPMG determined that the cost pool principles represent an appropriate guide for PNG to select its cost pools and these principles are appropriate for KPMG to assess PNG’s final cost pool sections against in this report (see Table 2a).

Final proposed shared cost pools were concluded to be consistent with those principles (see Table 2b).

19


4. Obtained details of PNG Management’s proposed shared cost pools. Reviewed and discussed the amounts and activities within shared cost pools prepared by PNG to determine whether the shared cost pools should be adjusted. As part of this procedure we reviewed job descriptions of individuals within the shared cost pools and conducted interviews with relevant PNG Management and staff.

Completed. Shared cost pools noted in Table 2b reflect these discussions.

5. Discussed and reviewed general ledger budget costs which were not allocated to a shared cost pool with Management and divisional managers to assess if related costs were incurred for the benefit of PNG(NE) and should be included in the shared cost pools.

Completed. No additional costs were noted.

6. Reviewed shared cost pools, including labour and/or non-labour components, and discussed and reviewed costs to see if other general ledger costs were associated with these costs and therefore should be included in these shared cost pools.

Completed. No additional costs were noted

7. Reviewed personnel assigned to shared cost pools and enquired of Management if other individuals are associated with services benefiting PNG(NE).

Completed. No additional individuals were noted and as a result labour components were complete.

8. KPMG discussed organizational changes with Management that may change shared cost pools and assessed if changes to cost pools were supported.

Completed. All necessary changes were reflected in the final cost pools.

9. For one individual in each shared cost pool, agreed their roles to job descriptions, employee organizational charts and time study results to time sheets.

Completed. No issues were noted.

10. Reconcile shared cost pools details to PNG’s 2012 budget figures from its Revenue Requirement Application, as updated on March 15, 2012.

Completed. Amounts reconciled. Management also changed certain shared cost pools for known changes in personnel duties in 2013, not reflected in the 2012 budget, which was appropriate.

5.2.2 Cost Allocators and Cost Allocation Methodology

1. Compared the proposed cost allocators to historical cost allocators.

Completed and noted that changes were preferable and supported.

20


2. Evaluated the appropriateness of each cost driver for allocation of cost pool expenditures against internal cost driver principles (included in Appendix A.2), including identification of options (where applicable), and their pros and cons.

Completed, no issues noted. See summary assessment (Table 3 for evaluation of cost allocator principles and Table 4 for proposed allocator by shared cost pool).

5.2.3 Time Based Allocator, Time Study and Employee Benefit Expense load rate applied to labour cost charged

1. Reviewed the information collected from PNG’s Time Study and assessed the quality of the information collected

(i) assessed the appropriateness of people included;

Completed. KPMG discussed with Management and concluded that the individuals who participated in the time study were appropriate as they performed shared services.

KPMG compared a sample of individuals whom participated in the time study to a PNG employee organization chart where their role and position supported shared services and were therefore appropriately included in the time study.

(ii) assessed how the results were allocated to each cost pool with a labour component;

KPMG reviewed the individual employee time allocations with management. We ensured significant changes from historic time allocations between PNG(NE) or non-PNG(NE) allocations were assessed and resolved. No significant unresolved issues were noted.

(iii) assessed the appropriateness of the Time Study as an allocation driver for the labour component of cost pools and in certain instances, the non-labour component of cost pools;

Time study as an allocator was discussed with management. KPMG found that the use of the Time Study as a time based allocator for the proposed labour cost components to be the most relevant cost allocator for all labour related activities and costs when compared to other alternative cost drives (e.g., rate base, customer count or employee count numbers).

The time study also served as a relevant input into composite average allocators for non-labour proposal components of cost pools (where time input is a relevant factor in its costs) formed a reasonable and objective basis of allocation.

21


(iv) The time study results, by individual, were allocated by Management to the individual labour components of shared cost pools (i.e. shared cost pools 721,711,713,714, and 685 as detailed in Table 2). KPMG assessed the basis of this allocation in comparison to the details in the employee organization chart, budget details and discussions with management.

Completed.

Any unusual results were reassessed with employees or their supervisors. No issues were noted that required re-assessments of individual records of time.

2. Re-perform calculation of the allocator related to number of employees to payroll and other supporting information.

Completed. No difference was noted.

3. Assessed the method that PNG Management utilized in order to determine the employee benefit expense load as part of the allocation of labour costs to the shared cost pools and tested certain data on a sample basis.

The employee benefit expense load includes the following more significant benefits that are added to the cost basis of labour and then shared between PNG and PNG(NE):

- Life and disability premium costs

- Medical and dental

- Savings and pension plan

- CPP and EI

Completed. KPMG finds that the employee benefit expense load rate applied to labour costs charged to be relevant and appropriate to include based upon the sample procedures performed.

4. Discussed alternate cost drivers with Management the pros and cons of the recommended changes.

The discussions supported the final cost drivers selected by PNG.

KPMG discussed with Management the allocators included in each composite allocator assigned to each non-labour component of each cost pool and found that the allocators assigned were reasonable as they influenced the level of costs in each pool.

5. Obtain from Management, back-up documentation (i.e. payroll reports) to support the numbers use to derive non-time allocators (customer count, employee count, and rate base).

Completed, no issues were noted.

22


5.2.4 Final Report

1. Ensured Management’s final cost drivers are aligned with the working steps outlined in steps 5.2.2 and 5.2.3 above.

Completed. Final cost drivers reflect all discussions and assessments with Management and are consistent with internal assessment principles.

2. Validated the mathematical accuracy of the final updated allocation model, using cost pool figures derived from PNG’s 2012 revenue requirements application, as updated on March 15, 2012. Re-performed allocations using the final cost allocators and discussed the resulting allocation with Management to ensure the PNG(NE) allocation was reasonable in nature and amount.

Completed. No issues noted. See the resulting allocations in the tables that follow.

23

5.3 Shared Service Cost Pool Evaluation Criteria

Table 2a provides an assessment of the basic principles PNG uses to evaluate cost pools to ensure that cost pools are relevant and appropriate.

PNG applied the following basic assessment criteria (see also Appendix A) when evaluating which shared goods or service expenditures of PNG should be included in cost pools to be allocated to PNG(NE) in its cost allocation model.

KPMG reviewed and assessed the principles to see if they represent relevant and appropriate evaluation criteria for PNG in developing its cost pools and also for KPMG to assess final cost pools against in concluding whether they are relevant and appropriate.

Table 2a

Basic Evaluation Principles Assessment whether these represent

appropriate evaluation criteria for PNG and KPMG’s evaluation if the cost pools are

relevant and appropriate

The goods or services must have one or some of the following basic attributes to be included in a shared cost pool to be allocated to PNG(NE):

The goods acquired by or services performed at the Vancouver corporate office or the Terrace regional office provide a direct or indirect benefit to PNG(NE) or its customer base.

Yes.

If the goods are no longer acquired or the services are ceased, PNG(NE) would be negatively impacted and PNG(NE) would have to find another source for such good or service or perform such service on its own. The service would be performed by PNG(NE) if it was a standalone operation performing its own service, compliance and reporting functions.

Yes.

Conclusion: The cost pool principles above form as an appropriate guide for PNG to determine its cost pools and for KPMG to evaluate PNG’s final selected cost pools against.

Table 2b provides a summary of the final shared service cost pools and concludes if they meet these principles based upon our procedures and are therefore relevant and appropriate.

24

Table 2b – Summary of Shared Service Cost Pools


Cost Pool Consistent with

Principles in Appendix A

Total $ Value of Proposed Cost

Pool (1)

Cost Pool is Relevant and Appropriate / Principles are Met


Yes 4,019,893 Yes


Yes 1,284,465 Yes


Yes 365,870 Yes


Yes 1,141,763 Yes

685 – Terrace Accounting (formerly Terrace Accounting/ Warehouse)

Yes 516,090 Yes

685 – Terrace Technical Services – Warehouse / Corrosion (new)

Yes 205,246 Yes


Yes 70,553 Yes


Yes 87,427 Yes


Yes 519,588 Yes


Yes 946,986 Yes


Yes 253,055 Yes


Yes 810,437 Yes

(1) These cost pool figures are derived from PNG’s 2012 revenue requirement application, as updated on March 15, 2012.

Conclusion: The cost final cost pools selected by PNG meet the principles described in Table 2a based upon our procedures performed and are viewed to be relevant and appropriate.

25

5.4 Evaluation of Cost Driver Principles Used

Table 3 provides a summary of the cost driver principles that are consistent with Management’s assessment principles in Appendix A.

Table 3 - Evaluation of Cost Driver Principles Used

Key: S = satisfies as an evaluation criteria SS = somewhat satisfies as an evaluation criteria NS = does not satisfy as an evaluation criteria

Evaluation Criteria Assessment Explanation

Defensible cost causation linkage

S The driver provides a causal link based on a level of effort or

investment with the PNG(NE) service activity for costs to be allocated to PNG(NE).

Freedom from bias S The cost driver selected would not be viewed to favor PNG(NE) or PNG-West unfairly.

Transparency S The driver used and the source or basis on how it is determined is visible to all parties affected.

Stability S The identified driver fluctuates as expected based upon the level of

effort and investment. It would not be expected that this driver would have to be amended or replaced in less than 12 months.

Accuracy S The identified driver allocates costs without users having to apply

estimation or judgment and the resulting allocation reflects a quantifiable allocation.

Sustainability S The identified driver can be supported into the foreseeable future without undue cost burden on PNG.

Cost versus benefit for effectiveness

S The cost to identify, capture data and utilize the identified cost driver is not too burdensome relating to the benefits of its application.

Availability of information to apply drivers

S The information needed to apply the cost driver is readily accessible.

Conclusion: KPMG is of the view that the shared cost pools and the cost allocator’s principles in Appendix A and noted above form a reasonable guide for PNG’s cost pool and cost allocator selection process and are appropriate principles for KPMG to assess PNG’s final selected cost pools and cost allocators.

26

5.5 Specific Cost Allocation Drivers Applied to Each Shared Cost Pool

Table 4 shows the final cost allocators for each shared cost pool. The cost drivers proposed by PNG are assessed against each these principles in Table 4 using the “Key” in Table 3.

Table 4 - Specific Cost Allocation Drivers Applied to Each Shared Cost Pool

Shared Service Cost Pool Historic Cost Allocator

Proposed

Cost Allocator

Allocator satisfies all the principles listed in Table

3


Labour component Time- based Time-based Yes-S

Non- labour components Time- based Composite

Average Allocator A(1)

Yes-S


Labour component Customer count Time-based Yes-S

Non-labour component Customer count Composite Average

Allocators B(1) Yes-S


Labour component Customer count Customer Count Yes-S

Non-labour component Customer count Customer Count Yes-S


Labour component Time-based Time-based Yes-S

Non-labour component n/a Composite


Yes-S


Labour component Employee count Time-based Yes-S

Non-labour component Employee count Composite


Yes-S

27

Shared Service Cost Pool Historic Cost Allocator

Proposed

Cost Allocator

Allocator satisfies all the principles listed in Table

3

685 – Terrace Technical Services- Warehouse/Corrosion (new)

Labour component Employee count n/a NA

Non-labour component Employee count Composite

Average Allocator C(1)

Yes-S


Labour component Customer count n/a N/A

Non-labour component Customer count Composite


Yes-S


Non-labour component Time study Composite


Yes-S


Non-labour component Rate base Composite


Yes-S


Non-labour component Customer count Customer Count Yes-S


Non-labour component Operating Margin Composite


Yes-S


Non-labour component Insurance Composite

Insurance Composite

Yes-S

(1) Management elected to use an average or composite allocator for the non-labour component as the chosen allocators influence this cost pool component. Composite Average Allocator A - this is an average of allocators including Time-Based, Customer Count, Employee Count and Rate Base allocators which influence the cost pool. Composite Average Allocator B - this is an average of allocators including Time-Based and Customer Count Allocators which influence the cost pool. Composite Average Allocator C - this is an average of allocators including Customer Count, Employee Count and Rate Base allocators which influence the cost pool.

28

5.6 Summary of Shared Service Cost Allocators

Table 5 shows the final proposed cost pools and allocators and resulting allocations prepared by Management (see also Appendix B), using cost pool figures derived from PNG’s 2012 revenue requirements application, as updated on March 15, 2012. KPMG re-performed the allocations and reflected the results in this table.

Table 5 - Summary of Shared Service Cost Allocators

Shared Service Cost Pool (see Table 1 also)

Proposed Cost Allocator

Total $ Value of Proposed Cost Pool

Allocated to NE Using Proposed

Allocators(1)

% of Proposed Cost Pool Allocated to NE

Using Proposed Allocators (prior

allocation)

KPMG reperformance of

allocation agrees to client’s allocation


Labour component Time- based

931,272 28.9% (20.8%) Yes

Non- labour components

Composite Average Allocator A(2) 251,616 31.7% (20.8%) Yes



554,169 49.2% (48.2%) Yes


Composite Average Allocators B(2)

77,047 48.7% (48.2%) Yes


Labour component Customer Count 95,176 48.2%(3) (-%)(3) Yes


Customer Count 81,096 48.2% (-%)(3) Yes


Labour component Time-based 324,064 36.9% (48.2%) Yes


Composite Average Allocator A(2)

88,938 33.7% (-%) Yes



204,282 42.4% (23.9%) Yes


Composite Average Allocator A(2) 12,029 35.1% (23.9%) Yes

29


Proposed Cost Allocator

Total $ Value of Proposed Cost Pool

Allocated to NE Using Proposed

Allocators(1)


Using Proposed Allocators (prior

allocation)

KPMG reperformance of

allocation agrees to client’s allocation

685 – Terrace Technical Services - Warehouse/Corrosion (new)


Composite Average Allocator C(2) 67,108 32.7% (-%)(4) Yes



Composite Average Allocator C(2) 23,068 32.7% (48.2%) Yes



Composite Average Allocator C(2) 28,585 32.7% (20.8%) Yes



Composite Average Allocator C(2)

169,886 32.7% (26.1%) Yes



Customer count 456,142 48.2% (48.2%) Yes



Composite Average Allocator C(2)

82,740 32.7% (32.5%) Yes



Insurance Composite

101,665 12.5% (12.5%) Yes

3,548,883

(3,016,436) 34.7% (30.5%)

(1) The cost pool figures are derived from PNG’s 2012 revenue requirements application, as updated on March 15, 2012

(2) Management elected to use an average or composite allocator for the non-labour component as the chosen allocators influence this cost pool component.

Composite Average Allocator A - this is an average of allocators including Time-Based, Customer Count, Employee Count and Rate Base allocators which influence the cost pool. . (See Appendix B.4.4 Composite Allocators)

30

Composite Average Allocator B - this is an average of allocators including Time-Based and Customer Count Allocators which influence the cost pool. . (See Appendix B.4.4 Composite Allocators)

Composite Average Allocator C - this is an average of allocators including Customer Count, Employee Count and Rate Base allocators which influence the cost pool. . (See Appendix B.4.4 Composite Allocators)

(3) Included with 711/713/714 – Terrace Customer Care in prior years. The labour component was allocated based upon customer count as it influenced the level of labour costs significantly. (4) Included with 685 – Terrace Accounting in prior years.

5.7 KPMG Conclusion – Shared Service Cost Allocation

Based on the results of its procedures, KPMG is of the view that the final shared cost pools and cost allocators proposed for use in the PNG shared services cost allocation model meet the internal objectives and principles criteria established by PNG as detailed in Appendix A and, as a result, form a reasonable and objective basis of cost allocation.

31

5.8 Assessment of Standalone of Customer Care Centre for PNG(NE)

KPMG assessed PNG’s estimate of annual operating and start-up costs of a standalone call centre in Fort St. John (included in Appendix C) by performing the following assessment procedures:

Procedure Findings

1. Obtained Management’s summary of annual operating costs and initial start up costs and ensured they were consistent with the final summary in Appendix C.

Completed, the summary is consistent with Appendix C.

2. Ensured that the summary totals and spreadsheet formulas are mathematically correct.


3. Reviewed the assumptions applied underlying the cost estimates for reasonableness on a line-by-line basis.

Completed. Significant assumptions noted in Appendix C were reasonable and were applied in arriving at cost estimates.

4. Reviewed the aggregated costs allocated to PNG(NE) relating to the Customer Care Centre under the current structure.

Completed. See Table B, Appendix B.

5. Reviewed the aggregated costs allocated to PNG(NE) relating to the Customer Care Centre under the newly proposed standalone care centre.

Completed. See Table B, Appendix B.

6. Assessed the costs estimated for a standalone Customer Care Centre, including assumptions behind the costs.

Completed. See Table C and D, Appendix C.

7. Assessed the completeness and breadth of costs captured and assumptions by:

comparing those to PNG’s existing customer care centre costs: and

comparing them to other customer care assessment projects which KPMG has been involved with.

Completed. The costs captured were viewed as complete and of adequate breadth.

32

Procedure Findings

8. Assess the accuracy of cost estimates by agreeing a judgmental sample of the costs to vendor invoices for its existing care centre, vendor quotes, labour contract rates and terms, payroll records for existing care centre staff.

Completed.

The following comments were provided for known differences, which were agreed by Management and adjusted for in arriving a the final summaries in Appendix C:

Reduced assumed costs for answering service line from $12,000 to $5,400

Training costs were increased for the 7 CSRs being trained versus 5 recognized in error.

Telephone costs were not 50% of current costs as the client had intended so this was corrected by PNG reducing costs from $32,000 to $18,000.

9. Test Operating Cost items over $5,000 to supporting records (vendor quotes and existing customer care costs) and assess if allocation thereof is reasonable.


10. Discussed basis for the increase in staff for the standalone facility and also tested salary and benefits assumptions for a CSR staff and a manager to existing labour contract terms for similar positions.


11. Test employee benefits estimates. Benefit loads are based on a percentage of employee salary, determined by level and if union or non-union. Compared benefit % for 1 CSR employee and 1 Manager to payroll and other records.


12. Test leasing and related utilities costs by comparing estimated lease rates to third party lease rates in the Fort St. John region.

Based upon market data on lease rates, the lease rate of $19/sq ft was viewed as a reasonable approximation for the Fort St. John realty market.

13. Estimate utilities and other leased property operating costs, the client estimated costs based upon the proposed square footage or ratio of employees etc.

KPMG re-performed this procedure and compared the results.

33

Procedure Findings

14. Test training cost assumptions; compare number of employees being trained to number of assumed new hires and also instructor rates and trainee pay rates to payroll records on a sample basis.


15. Test severance and recruitment costs by comparing key severance assumptions for the 5 CSRs affected (average salary, service and week entitlement) to pension and labour contract terms.


16. Assess variance to the estimated costs for the Standalone Customer Care Centre.

Management believes that actual costs of the customer care centre could be ±10-15% of these estimated cost amounts due to variations in negotiated supplier and lease terms, training needs and recruitment costs, amongst other factors.

KPMG is of the view this is reasonable.

5.9 KPMG Conclusion – Standalone Customer Care Centre

Based upon the results of the above procedures, KPMG is of the view that the estimated summary of annual operating and start-up costs for the proposed standalone call centre in Fort St. John to be within a reasonable range, after reflecting certain immaterial adjustments proposed by KPMG based upon our findings and ultimately recognized by PNG.

34

Appendix A – PNG’s Shared Services Cost Allocation Principles

A.1 Shared Cost Pools – PNG Management Basic Assessment Criteria

Management applies the following basic assessment criteria when evaluating which shared goods or service expenditures of Pacific Northern Gas Ltd. (“PNG”) should be included in cost pools to be allocated to Pacific Northern Gas (N.E.) Ltd. (“PNG(NE)”) in its cost allocation model. Management has also represented that this same criteria was applied in determining its historic shared cost pools.

The goods or services must have one or some of the following basic attributes to be included in a shared cost pool to be allocated to PNG(NE):

The goods acquired by or services performed at the Vancouver corporate office or the Terrace regional office provide a direct or indirect benefit to PNG(NE) or its customer base.

If the goods are no longer acquired or the services are ceased, PNG(NE) would be negatively impacted and PNG(NE) would have to find another source for such good or service or perform such service on its own.

The service would be performed by PNG(NE) if it was a standalone operation performing its own service, compliance and reporting functions.

A.2 Cost Drivers – PNG Management Cost Driver Assessment Principles

Management applies the following commonly used cost driver assessment principles when evaluating which cost driver should be used to allocate a cost pool or specific costs within a cost pool between PNG or PNG(NE):

Cost-causality - The identified driver, being it work effort or investment, has a direct correlation to the cost of the services or goods and also has a direct effect on the level of service.

Freedom from bias - The cost driver selected would not be viewed to favor PNG(NE) or PNG unfairly.

Transparency - The driver used and the source or basis on how it is determined is visible to all parties affected.

Stability - The identified driver fluctuates as expected based upon the level of effort and investment. It would not be expected that this driver would have to be amended or replaced in less than 12 months

Accuracy - The identified driver allocates costs without users having to apply estimation or judgment and the resulting allocation reflects a quantifiable allocation.

Sustainability - The identified driver can be supported into the foreseeable future.

Cost versus benefit for effectiveness - The cost to utilize the identified cost driver supports the resulting benefits of its application.

Availability of information to apply drivers - The information needed to apply the cost driver is readily accessible.

35

Appendix B – Summary of PNG’s Current Shared Services Cost Allocation Model and Proposed Changes Thereto

B.1 Summary of PNG’s Shared Service Cost Allocation Model

This section summarizes the key components of the shared service cost allocation methodology and the proposed changes to the model to be applied in 2013.

PNG provides a number of administrative, accounting and regulatory and other reporting services, directly or indirectly, for the benefit PNG(NE). Since the results of PNG(NE) are separately reported to the Commission, it is necessary to use an allocation model to allocate the appropriate amount of shared costs to PNG(NE) for the services benefits it receives each reporting period. PNG currently allocates its costs for such services to PNG(NE) using a number of different cost allocators, including allocators based upon relative time, relative number of customers, relative number of employees and relative rate base.

Management identified and assigned a qualified team of internal staff members to evaluate the shared service cost allocation model in this current year’s study. Experienced management and other personnel assigned to the project included the project leaders - the VP Regulatory Affairs and Gas Supply and the Manager of Regulatory Affairs and Special Projects, supported by the General Manager Operations, Manager Terrace Customer Care Centre, IT Manager and the VP Human Resources and Government Relations.

B.2 Costs Shared Between PNG and PNG(NE) (Shared Cost Pools)

The first step performed by PNG Management in assessing and finalizing a revised shared services cost allocation model to be applied in 2013 and future years was to review the activities undertaken and captured within the expenses of historic identified shared cost pools. This assessment was to validate shared activities which provide services and goods to PNG(NE) currently and/or if they require revisions using the principles described in Appendix A as a guide.

The following accounts and shared cost pools capture shared costs incurred by PNG Vancouver and the Terrace regional office for the benefit of PNG(NE) and have been used for many years:

1) Account 721 – Vancouver Administration

2) Accounts 711/713/714 – Terrace Customer Care Centre

3) Account 685 – Terrace Management

4) Account 685 – Terrace Accounting/Warehouse

5) Account 728 – Corporate Expenses

6) Account 685 – Terrace Drafting

7) Account 685 – Terrace Engineering

8) Account 713 – Vancouver Vertex Billing Services

9) Account 722 – Vancouver Special Services

10) Account 723 – Vancouver Insurance

36

PNG project management reviewed the cost pools identified above with key management staff in Vancouver and Terrace to assess if the current cost pools were appropriate and/or if additions or deletions to the cost pools should be made. The individual costs within each pool were also reviewed to assess if any costs should be removed from the allocation pool. This review identified whether a cost is no longer shared but now fully relates to PNG(NE) or PNG-West given its nature.

Management also reviewed all other costs in the general ledger that were not historically allocated to a shared cost pool and assessed if any of these non-allocated general ledger cost accounts should be allocated and included as a shared cost.

Table A below summarizes PNG’s updated final shared cost pools as determined by PNG Management based upon this review:

Table A – Summary of Shared Service Cost Pools


Provides Services Shared

Between PNG(NE) and

PNG

Historic

Cost

Pool

Total $ Value of Historic Cost

Pool(1)


Pool(1)

Total $ Change in Cost Pool(1)


Yes Yes 3,923,340 4,019,893 96,553


Yes Yes 1,642,472 1,284,465 (358,007)


Yes No – 365,870 365,870


Yes Yes 698,627 1,141,763 443,136

685 – Terrace Accounting (formerly Terrace Accounting/ Warehouse)

Yes Yes 772,230 516,090 (256,140)

685 – Terrace Technical Services – Warehouse / Corrosion (new)

Yes No – 205,246 205,246


Yes Yes 163,473 70,553 (92,920)


Yes Yes 198,844 87,427 (111,417)


Yes Yes 519,588 519,588 –


Yes Yes 946,986 946,986 –


Yes Yes 223,914 253,055 29,141


Yes Yes 810,437 810,437 –

9,899,911 10,221,373 321,462

(1) These cost pool figures are derived from PNG’s 2012 revenue requirement application, as updated on March 15, 2012.

37

The discussion that follows describes the services performed by the cost pool functional areas identified in Table A, and the changes made by Management under this updated allocation model and the basis for these changes.


The Vancouver head office provides corporate and administrative services for PNG, including PNG(NE). PNG(NE) does not employ any administrative service employees and therefore relies on head office for support. A large portion of this cost pool consists of labour costs provided by the following positions:

President IT Manager

Executive Assistant Senior Network Administrator (2)

Vice President Finance & Corporate Development

Vice President, Regulatory Affairs & Gas Supply

Controller Manager Regulatory Affairs & Special Projects

Manager Financial Reporting & Taxation Senior Regulatory Analyst

Manager Corporate Accounting Vice President Human Resources & Government Relations

Financial Analyst Payroll/Benefits Administrator

Manager Financial Planning and Business Development

Manager Financial Systems & Controls

A summary of many of the Account 721 administrative services provided by PNG to PNG(NE) is given below:

Corporate governance, corporate policy and strategic direction;

Management of all financing activities, including relationship management with short and long term lenders, reporting to lenders, and ensuring compliance with the trust deed;

Maintenance of Corporate legal records and administration of all legal-related matters;

Management of all employee benefit programs, including Company Pension, Savings Plan, Extended Health programs and Pension Fund investment review and management. Preparation of Pension Fund and Savings Plan remittances and Pension Fund financial record keeping;

All regulatory services, including preparation and filing of regulatory applications, tariffs, responses to information requests, preparation of quarterly reports on gas supply costs, and attendance at public hearings and negotiated settlement proceedings;

Gas purchasing management, including negotiation of contracts with suppliers.

Insurance procurement and management services;

All advanced accounting functions, including preparation and distribution of management reports, project reports, and financial statements, budgeting;

38

Review of all financial information by the Disclosure Committee (a management committee);

Preparation of material required by external auditors to complete the annual financial statement audit of PNG(NE);

Preparation of Statistics Canada reports, including Natural Gas Distribution Report, Natural Gas Disposition Report, Survey of Environment Protection Expenditures; Natural Gas Transport and Distribution Report, Capital Expenditures, Estimates and Forecasts, and Capital and Repairs Expenditures Report, processing of tax remittances and returns, Worker’s Compensation returns, and T4 and T4A slips;

Preparation of manual bills for industrial sales and transport customers not billed through the computer based Banner System, drafting of industrial customer gas sales and transportation service contracts;

All IT services and management, including management of existing IT assets, Help Desk services to all PNG(NE) employees, network administration, security and support, and hardware procurement; and

Preparation of compliance reporting, including Statistics Canada reports, Natural Gas Distribution Report, Natural Gas Disposition Report, Survey of Environment Protection Expenditures; Natural Gas Transport and Distribution Report, Capital Expenditures, Estimates and Forecasts, and Capital and Repairs Expenditures Report, processing of tax remittances and tax returns (corporate, commodity taxes), Worker’s Compensation returns, and T4 and T4A slips.

Cost Pool Changes

Based on Management’s review of underlying costs included in the Vancouver Administration cost pool, the proposed cost pool has been increased by $96,553, primarily due to the inclusion of the labour and benefits costs associated with the office receptionist / administrative assistant. These costs were historically excluded from this pool, however, this role actively assists with corporate accounting activities which support PNG(NE) and are appropriately included in this pool.


The Customer Care Centre in Terrace serves PNG’s customer base across all divisions. The labour positions included in this cost pool are:

• 11 Customer Service Representatives in Terrace; and

• 1 Meter Records Clerk in Terrace.

A summary in point form of many of the Account 711/713/714 Customer Care Centre services provided by PNG to PNG(NE) is given below:

All Customer Care Centre activities for all of the NE and PNG-West division customers, including call centre information services, establishment of new accounts, maintenance of customer accounts, preparation of change orders, collection of overdue accounts, issuance of disconnection notices;

Meter inventory record keeping and processing of meter reads;

Accounts receivable, customer payment processing, management of grant and rebate programs;

39

Introduction, implementation and direction of new programs and services to facilitate a more efficient work flow and tracks new service line costs and coordinates billing of service line costs; and

Respond to customer complaints on a one-on-one basis.

Cost Pool Changes

Historically, the Vancouver Billing Services function has been included in this cost pool. Based on the review of cost pools, based on the distinct services provided by Vancouver Billing Services it has been segregated into its own cost pool.

Based on Management’s review of underlying costs included in the Terrace Customer Care Centre cost pool, the proposed cost pool has been reduced by $358,007, comprised of the following elements:

Remove $378,737 in costs related to the Vancouver Billing Services function which has been segregated into a new cost pool; and

Add $20,495 in costs primarily related to Itron meter maintenance that were historically excluded from this pool


Historically, the Vancouver Billing Services function has been grouped together with the Terrace Customer Care Centre function. However, given the very different service activities performed by this functional area, it has been segregated into its own cost pool.

The Vancouver Billing Services group includes the following human resources:

• 1 Coordinator Customer Information Systems; and

• 1 Billing Analyst.

Billing Services is responsible for maintenance and administration of the Banner customer billing system used to bill all of PNG and PNG(NE)’s residential and commercial customers, as well as some industrial customers. Key functions performed by this group include:

Project management and testing of Banner billing system upgrades and customer rate changes;

User support for the Banner customer billing system; and

Onsite training for personnel on various matters relating to the Banner billing system and the SharePoint platform.

Cost Pool Changes

Management has identified $365,870 in costs related to this new cost pool, including:

Reclassification of $378,737 in costs historically grouped with Terrace Customer Care Centre;

Reduction in allocation of labour benefits by $39,420 due to adjustment to benefit load rate applicable to labour costs in this pool (non-bargaining unit employees); and

Add $26,554 in costs primarily related to data service lines historically excluded from shared services cost pools.

40


There are nine non-bargaining unit staff members included in the Terrace Management cost pool responsible for the management and administration of all operational activities for the PNG-West division and some in support of the PNG(NE) divisions. The following is a summary of the roles performed by these functions:

1) General Manager Operations

Responsible for oversight, operation and administration of all field operations for PNG-West and PNG(NE).

2) Manager Customer Care

Manages Customer Care Center and meter records operations and staff which serve all PNG-West and PNG(NE) customers;

3) Operations Accounting Manager

Manages Operations Accounting group responsible for day-to-day accounting activities for both PNG-West and PNG(NE).

4) Coordinator Marketing & Lands

Provides services for sales and marketing, lands and rights-of-way and pipeline public awareness services for PNG-West and PNG(NE).

5) Manager Community Relations & Administration

Provides community relations and administrative services to the PNG-West and PNG(NE) divisions.

6) Manager Engineering & Special Projects

Responsible for engineering services across both the PNG-West and NE divisions, including coordination of pipeline construction and repairs, oversight of outside contractors and engineering service; and

Manages direct report in Drafting area that provides service directly to PNG(NE).

7) Manager Technical Services

Responsible for managing Terrace-based technical field staff in the areas of Warehouse, Compression, Corrosion and Measurement;

Has little direct involvement in PNG(NE) activities, however is responsible for fleet management and engineering design work that benefits the PNG(NE) divisions;

Manages direct reports in areas of Warehouse and Corrosion that provide service directly to PNG(NE); and

Manages direct reports in areas of Compression and Measurement that provide negligible support to PNG(NE) activities.

8) Manager Construction Maintenance

Responsible for managing construction and maintenance activities for PNG-West;

Negligible involvement in PNG(NE) activities.

41

9) Manager Customer Service

Responsible for managing customer service activities for customers in the PNG-West service area; and

Negligible involvement in PNG(NE) activities.

Cost Pool Changes

Management’s review of this cost pool has identified $443,136 in additional costs being included in this pool, as discussed below.

Labour Costs

Historically, the cost pool for Terrace Management included the labour costs related to positions 2) through 7) above, specifically the following 6 positions:

Manager Customer Care Operations Accounting Manager Coordinator Marketing & Lands Manager Community Relations & Administration Manager Engineering & Special Projects (30%) Manager Technical Services

Based on Management’s review of this cost pool the following amendments have been proposed for the new cost pool:

Add labour costs related to the General Manager Operations; this is a new position that evolved from the Manager Operations, West which had historically only had involvement in PNG-West activities; the new position has responsibility for all field operations, including both PNG-West and PNG(NE);

Include 100% of labour costs of Manager Engineering & Special Projects; previous provision was for 30% of the labour costs attributed to oversight of Drafting function, however, support provided to PNG(NE) is much broader in base therefore inclusion of 100% of labour is considered valid;

Exclude labour costs for Manager Technical Services; updated time study results indicate that negligible time is spent in support of PNG(NE) activities;

The proposed cost pool for Terrace Management includes labour costs related to positions 1) through 6) above, specifically for the following 6 positions:

General Manager Operations Manager Customer Care Operations Accounting Manager Coordinator Marketing & Lands Manager Community Relations & Administration Manager Engineering & Special Projects

The net effect of this change is a $179,827 increase in labour-related costs in this cost pool.

42

Other Costs

Historically, only labour costs have been included in this cost pool. Based on Management’s review of costs related to Terrace Management, the proposed cost pool includes $263,540 in additional costs, comprised of the following items:

With the establishment of the position General Manager Operations, $111,417 in costs related to operational licenses and permits have been transferred from the Terrace Safety & Training (formerly Terrace Engineering) cost pool to include these costs in the appropriate area of responsibility;

Add $72,599 in costs primarily related to corporate-wide initiatives in the areas of training and safety and other operational permitting and licensing requirements;

Add $43,942 in costs related to Records Administration services the encompass activities in both PNG-West and PNG(NE); and

Add $35,582 in costs related to Marketing & Lands services the encompass activities in both PNG-West and PNG(NE).


Historically, the Terrace Accounting and Terrace Warehouse functions were grouped together into a single cost pool. Given the distinctiveness of these functional areas, Terrace Accounting has been established as a separate cost pool. Terrace Warehouse costs have been reclassified to the proposed new Terrace Technical Services – Warehouse/Corrosion cost pool, as discussed below.

Employees included in the Terrace Accounting cost pool provide complete field accounting services to both PNG-West and PNG(NE) divisions, including processing and archival of all vendor invoices, plant accounting, employee time recording and payroll, and equipment usage record keeping.

Cost Pool Changes

Based on Management’s review of underlying costs included in the Terrace Accounting cost pool, the proposed cost pool has been reduced by $256,140, comprised of the following elements:

Reclassification of Terrace Warehouse costs of $248,212 to the new Terrace Technical Services – Warehouse/Corrosion cost pool;

Add $9,760 in costs primarily related to training that were historically excluded from this pool; and

Remove $17,688 in costs related to the Terrace Management function that were incorrectly classified in this cost pool.

685 – Terrace Technical Services – Warehouse/Corrosion (new)

Historically, the Terrace Warehouse and Terrace Accounting functions were grouped together into a single cost pool. Given the distinctiveness of these functional areas, Terrace Warehouse costs have been reclassified to this proposed new Terrace Technical Services – Warehouse/Corrosion cost pool. Terrace Accounting was established as its own cost pool, as described previously.

43

As part of PNG Management’s shared services allocation review process, the review of Technical Services identified that the Warehouse and Corrosion service areas provided considerable support for PNG(NE) activities, whereas the Compression and Measurement service areas provided negligible support for this region. Based on these findings, this new Technical Services cost pool has been proposed for Warehouse and Corrosion functional costs.

Cost Pool Changes

Based on Management’s review of underlying costs related to Warehouse and Corrosion activities, a new cost pool of $205,246 has been proposed, comprised of the following elements:

Reclassification of Terrace Warehouse costs of $248,212 from the historical Terrace Accounting/Warehouse cost pool;

Elimination of all labour-related ($72,072) and travel-related ($871) Warehouse costs historically included in this pool as these costs are directly budgeted/charged to the PNG(NE) divisions;

Add $11,144 in Warehouse costs primarily related to purchasing that were excluded from historic cost pools; and

Add $18,833 in Corrosion costs excluded from historic cost pools.


The Terrace office has a single draftsperson provides drafting services to both the PNG-West and PNG(NE) divisions. The costs included in this cost pool pertain to the drafting function.

Cost Pool Changes

Based on Management’s review of underlying costs Terrace Drafting activities, the cost pool has been reduced by $92,920 to reflect the removal of all labour-related costs historically included in this pool. Drafting labour costs are directly budgeted/charged to the PNG(NE) divisions.


Historically, the Terrace Engineering cost pool captured costs related to operational safety and training, as well as operational licenses and permits that were administered out of the Vancouver office. As noted previously under the Terrace Management cost pool discussion, with the establishment of the position General Manager Operations, costs related to operational licenses and permits historically included in this cost pool have been transferred to the Terrace Management cost pool to align with the responsibility for these costs. This proposed cost pool includes only costs related to Terrace Safety & Training expenditures pertaining to programs that span the activities of PNG-West and PNG(NE).

Cost Pool Changes

Based on Management’s review the Terrace Safety & Training cost pool consists of $87,427 in costs historically included in the Terrace Engineering cost pool. As discussed above, the other $111,417 in costs included in the historic Terrace Engineering cost pool are related to operational licenses and permits and have been transferred to the Terrace Management cost pool.

44


Expense items included in the Vancouver Corporate Expense cost pool have historically related to public company costs. With the acquisition of PNG by AltaGas on December 20, 2011, many of these expenses have been eliminated as PNG is no longer a publicly-listed company.

The most significant cost item in this cost pool is a management fee charged by AltaGas for corporate services provided ($404,335). The remaining costs relate to corporate registrar fees, debt rating agency fees, corporate membership fees and communications and public relations costs.

PNG submits that all of the expenses in this pool are appropriate. As PNG(NE) is a wholly owned subsidiary of PNG, which is a subsidiary of AltaGas, PNG(NE) directly enjoys the benefits of PNG and AltaGas assuming the above corporate ownership responsibilities.

Cost Pool Changes

PNG Management’s review of costs included in this cost pool indicates that all relevant costs have been captured and no changes are proposed.


Expense items included in the Vancouver Vertex Billing Services cost pool primarily consist of service fees for PNG’s third-party billing services provider (Vertex) and billing-related postage costs. PNG submits that all of the expenses in this pool are appropriate.

Cost Pool Changes



The Vancouver Special Services cost pool consisted of external audit fees. All operations are included in PNG’s consolidated financial statements and subject to an annual audit to meet debt holder requirements and external reporting requirements required from being a subsidiary of a publicly traded company. PNG submits that all of the expenses in this pool are appropriate.

Cost Pool Changes

Based on Management’s review, this cost pool has been increased by $29,141 to include internal audit costs which have also been identified as appropriate for inclusion in this pool.


The Vancouver Insurance cost pool includes the premium cost for all insurance coverage other than automobile insurance. This includes property, liability, director and officer, and fiduciary coverage. Automobile insurance premiums are incorporated into the equipment operating cost allocation process. PNG submits that all of the expenses in this pool are appropriate.

Cost Pool Changes


45

B.3 Cost Pool Allocators (or “Drivers”)

B.3.1 Cost Driver Principles

Shared costs are required to be allocated between PNG(NE) and the balance of PNG. PNG Management has applied the following commonly used cost driver assessment principles when evaluating which cost driver should be used to allocate a cost pool or specific costs within a cost pool (component):

Cost-causality - The identified driver, being either related to work effort or investment, has a direct correlation to the cost of the services or goods and also has a direct effect on the level of service.

Freedom from bias - The cost driver selected would not be viewed to favor PNG(NE) or the rest of PNG unfairly.

Transparency - The driver used and the source or basis on how it is determined is visible to all parties affected.

Stability - the identified cost driver is robust and changes as expected over time based upon known and established factors. It would not be expected that this driver would have to be amended or replaced in less than 12 months from initial application.

Accuracy - The identified driver allocates costs without users having to apply estimation or judgment and the resulting allocation reflects a quantifiable allocation.

Sustainability - The identified driver can be calculated and supported into the foreseeable future.

Cost versus benefit for effectiveness - The cost to utilize the identified cost driver supports the resulting benefits of its application, and is not too onerous to collect the required underlying data.

Availability of information to apply drivers - The information needed to apply the cost driver is readily accessible.

B.3.2 Assessment of Appropriate Cost Drivers

The second step performed by PNG Management in assessing and deriving its revised 2012 shared services cost allocation model was to assess and finalize cost allocators for each cost pool and/or or cost pool component identified under step one above using the principles described in Appendix A as a guide.

The five shared cost allocators utilized historically and in 2012 are included in Table B below and include:

Time-based percentage allocator (relative time spent on PNG(NE) activities)

This allocator was derived from the results of a 2003 time study of Vancouver head office employees to estimate the time expended on PNG(NE) matters. The percentages derived from this study have been applied for years 2004 through 2012.

Customer count percentage allocator (relative PNG(NE) customers to total PNG customers)

This allocator is derived from internal customer count details supporting PNG’s annual revenue requirements applications. This allocator has changed over time with changes in the distribution of total customers between PNG-West and PNG(NE).

46

Employee count percentage allocator (relative PNG(NE) employees to total PNG employees)

This allocator is derived from internal employee count details and has changed over time with changes in the distribution of total employees between PNG-West and PNG(NE).

Rate base percentage allocator (relative PNG(NE) rate base to total PNG rate base)

This allocator is derived from divisional rate base details derived from PNG’s annual revenue requirements applications. This allocator has changed over time with changes in the distribution of total rate base between PNG-West and PNG(NE).

Operating margin allocator (relative PNG(NE) operating margin to total PNG operating margin)

This allocator is derived from divisional operating margin details derived from PNG’s annual revenue requirements applications. This allocator has changed over time with changes in the distribution of total operating margin between PNG-West and PNG(NE).

Insurance composite allocator

A composite insurance allocator for insurance costs was proposed and implemented as part of PNG’s 2005 revenue requirements application. The use of a composite allocator was considered appropriate given that insurance premium costs were impacted by a number of variables. As directed by BCUC Order G-42-05, allocators applied to specific premiums are as follows:

o Property – premiums allocated on basis of replacement value of assets, adjusted for estimated risk of claims;

o Commercial Liability – premiums allocated on basis of both customer count and net plant-in-service, weighted equally;

o Directors & Officers – premiums allocated on basis of net income; and

o Fiduciary – premiums allocated on basis of employee count.

PNG project management reviewed the cost pools with key management staff in Vancouver and Terrace to assess if the cost pools allocators of the prior year were appropriate and/or if changes were required due to changing activities and cost pool influencers. For new cost pools management identified the key individuals and activities of the pool to identify likely drivers of its costs.

B.3.3 Updated Time Study

As required by the Commission, a new 2011/2012 Time Study was completed to update the time-based allocator used by PNG Management. PNG Management, using the information from this updated July 2012 study, derived separate labour allocator percentages for each cost pool identified in step one. This differs from the historic approach where a general labour allocator based upon Vancouver office employees was applied on an overall basis.

47

A change to more specific labour allocations was viewed as more relevant. To develop these labour allocator percentages by cost pool, PNG Management:

(i) Identified staff performing activities in these cost pools, and

(ii) For identified staff, their time was allocated in each pool between:

a. PNG(NE) activities time;

b. Rest of PNG activities time; and

c. PNG non-regulated activities time.

In general, Management determined that the labour costs of each pool should be allocated based upon the updated time-based allocator for each respective pool.

B.3.4 Composite Allocators

The non-labour cost components in general were determined to be influenced by a number of relevant allocators. Based on this multiple influence, the decision was made to move from non-labour cost allocators based on specific factors to composite allocators based on an average of cost allocators relevant to each cost pool. The following summarizes composite allocators applied in the revised cost allocation model:

Composite Average Allocator A - this is an average of allocators including Time-Based, Customer Count, Employee Count and Rate Base allocators which influence the cost pool.

Composite Average Allocator B - this is an average of allocators including Time-Based and Customer Count Allocators which influence the cost pool.

Composite Average Allocator C - this is an average of allocators including Customer Count, Employee Count and Rate Base allocators which influence the cost pool.

B.3.5 Summary of Shared Service Cost Allocators

Table B that follows summarizes Management’s proposed cost allocators to be applied to each cost pool or cost pool element under its revised cost allocation model in comparison to allocators applied historically. The table also summarizes the resulting cost allocations and percentage allocations PNG(NE) to by cost pool or cost pool element under the new model in comparison to allocations in 2012.

48

Table B - Summary of Shared Service Cost Allocators


Historical Cost

Allocator

Proposed Cost

Allocator

Total $ Value of Historical Cost Pool Allocated

to NE Using Historical

Allocators(1)

% of Historical Cost Pool

Allocated to NE Using Historical

Allocators


Pool Allocated to NE Using Proposed

Allocators(1)


Using Proposed Allocators



Are the proposed allocators and final

allocation reasonable and consistent with



Labour component Time- based Time- based

652,400 20.8% 931,272 28.9% Updated time study results Yes

Non- labour components

Time- based Composite Average

Allocator A(2) 165,224 20.8% 251,616 31.7% A composite average of

relevant allocators Yes


Labour component Customer

count Time- based



Customer count

Composite Average

Allocators B(2) 134,551 48.2% 77,047 48.7% A composite average of




count Customer

Count – (3) –%(3) 95,176 48.2% Updated customer count Yes


Customer count

Customer Count – (3) –%(3) 81,096 48.2% Updated customer

count Yes



count Time-based 336,593 48.2% 324,064 36.9% Updated time study results Yes


n/a Composite Average

Allocator A(2) – –% 88,938 33.7% A composite average of


49


Historical Cost

Allocator

Proposed Cost

Allocator



Allocators(1)



Allocators



Allocators(1)









Labour component Employee

count Time- based



Employee count

Composite Average

Allocator A(2) 52,228 23.9% 12,029 35.1% A composite average of


685 – Terrace Technical Services- Warehouse/Corrosion (new)

Labour component Employee

count n/a – (4) –%(4) – –% No labour costs

allocated Yes


Employee count

Composite Average

Allocator C(2) – (4) –%(4) 67,108 32.7% A composite average of




count n/a 44,767 48.2% – –% No labour costs

allocated Yes


Customer count

Composite Average

Allocator C(2) 33,992 48.2% 23,068 32.7% A composite average of


50


Historical Cost

Allocator

Proposed Cost

Allocator



Allocators(1)



Allocators



Allocators(1)









Yes Non-labour

component Time study

Composite Average


relevant allocators


Yes Non-labour component

Rate base Composite Average


relevant allocators



Customer count

Customer count 456,142 48.2% 456,142 48.2% Updated customer

count Yes



Operating margin

Composite Average





Insurance Composite

Insurance Composite

101,665 12.5% 101,665 12.5% Updated insurance composite Yes

3,016,436 3,548,883

51

(1) The cost pool figures are derived from PNG’s 2012 revenue requirements application, as updated on March 15, 2012

(2) Management elected to use an average or composite allocator for the non-labour component as the chosen allocators influence this cost pool component.

Composite Average Allocator A - this is an average of allocators including Time-Based, Customer Count, Employee Count and Rate Base allocators which influence the cost pool.

Composite Average Allocator B - this is an average of allocators including Time-Based and Customer Count Allocators which influence the cost pool.

Composite Average Allocator C - this is an average of allocators including Customer Count, Employee Count and Rate Base allocators which influence the cost pool. (3) Included with 711/713/714 – Terrace Customer Care in prior years. The labour component was allocated based upon customer count as it influenced the level of labour costs. Billing matters are general in nature and are not specific to PNG(NE) and as a result time study results were not available or relevant. (4) Included with 685 – Terrace Accounting in prior years.

52

B.4 Management’s Conclusion – Shared Services Cost Allocation

Management determined that the final shared cost pools, cost allocators and resulting allocations under the new allocation model meet the internal objectives and principles established by PNG as detailed into Appendix A. The percentage allocations to PNG(NE) have increased in general and this is viewed to be a function of both increased activity and cost investment in PNG(NE) and also changes to the allocation model that reflect a more accurate allocation of PNG costs to PNG(NE).

53

Appendix C – PNG Management’s Standalone Customer Care Centre Assessment

C.1 Management’s Assessment Process and Procedures

Management’s assessment process involved the following steps and procedures:

Management identified and assigned a team of internal staff members with call centre experience and/or logistical knowledge that would be able to assess the costs and qualitative factors to be considered for a standalone call centre in the NE region. Experienced management and other personnel assigned to the project included: VP Regulatory Affairs and Gas Supply, Manager of Regulatory Affairs and Special Projects, General Manager Operations, Manager Terrace Customer Service Centre, IT Manager, and VP Human Resources and Government Relations.

Management developed a strategy to identify expected operating and capital costs of a new facility and presented the proposed strategy to KPMG. KPMG examined the strategy and provided commentary on the approach for PNG Management’s reconsideration.

The final strategy applied by PNG Management was:

To define the role and function of a call centre in the NE region - As the customer care function covers a broad range of services to customers, Management considered what customer care functions would be appropriately provided at a standalone facility in the NE region. For this exercise, it was established that the following services currently provided by the Terrace call centre would be replicated in order to serve NE customers:

Customer contracts and service orders

Customer billing and accounting assistance

Customer credit and collections services

The back office billing function using the Banner system would continue to be operated as a centralized service and is appropriately excluded from this analysis.

To identify a call centre location - Factors and variables considered included the prospects of a stable and/or growing economy at the proposed location, the depth of the existing labour market and the needs of the centre, PNG’s knowledge of the area, proximity to its existing and target customer base, and PNG’s existing service centres. Fort St. John is the largest city in British Columbia’s northeast region and has a growing and expanding community and business centre. One of PNG’s existing main operating offices is already located in Fort St. John, giving PNG knowledge and experience and potential operational synergies to establish a standalone call centre in this city. Based upon these factors Fort St. John was selected as the location for the proposed standalone call centre.

To develop operating and capital estimates:

Management identified key assumptions and call centre requirements that would drive cost estimates and they were concluded to be:

Existing Terrace call centre staff would not relocate to Fort St. John. All staff would be newly hired and would include 7 customer service representatives (“CSR”) and 1 manager;

54

Existing Terrace CSRs and managers would train newly hired staff while on leave of absence;

Five Redundant CSRs in Terrace would receive severance pay and provision for these amounts have been estimated based upon existing collective labour contract provisions;

Certain furniture and fixtures and other property and equipment (capital items) from its existing call centre operations in Terrace would be transferred and repurposed in the new proposed facility; and

Leasing office space is a more cost effective alternative to the physical expansion of the existing office or the purchase of additional office space.

To develop specific cost estimates:

Management first identified and reviewed its existing call centre’s operating and capital costs. These costs were assessed and evaluated as to whether they would be representative of the standalone costs for a Fort St. John operation and if not, were adjusted or revaluated and/or supported through vendor or agent quotes and management estimates from experienced and knowledgeable PNG personnel; and

Management considered whether it was more cost effective to lease an office versus expand existing facilities or purchase new office space and determined that leasing office space in Fort St. John was more cost effective and provided a more timely transition.

The Table C below presents management’s estimate of annual operating costs for a standalone customer call centre in Fort St. John:

Table C - Summary of Annual Operating Costs of Standalone Customer Care Centre Costs

Type of Costs Estimated Standalone Costs (2012) for Customer Care Centre in NE Region

General and Administrative $ 17,400

Training 4,200

Customer Contracts and Orders 16,750

Customer Billing and Accounting 13,700

Credit and Collections 19,000

Office Equipment Maintenance 2,500

Office Lease and Utilities 57,374

Salary and Benefits 703,598

Total Annual Expense $ 834,521

55

Table D below summarizes the estimated start-up costs of a standalone customer care centre in Fort St. John in the initial start-up year as developed by PNG Management. These costs are separate from the annual operating costs discussed above. It shows that there is a cost to invest in a new call centre of approximately $522,000.

Table D - Summary of Start-up Costs of Standalone Customer Care Centre

Type of Cost Estimated Start-up Costs (2012) of Standalone

Customer Care Centre in NE Region

Initial Training $ 230,475

Severance 150,000

Recruitment Costs 76,000

Capital Expenditures - Equipment and Fixtures 85,225

Total Startup Costs $ 541,700(1) (1) This estimate does not include the cost to purchase office space as leasing of office space was determined to

be more economical and practical.

The estimated annual operating costs and the initial start-up costs represent Management’s best estimate of the actual costs that it would incur in 2012, but Management also believes that actual costs could be ±10-15% of these estimated cost amounts due to variations in negotiated supplier and lease terms, training needs and recruitment costs, amongst other factors.

C.2 Management’s Quantitative Assessment

Management estimated annual operating costs of a new standalone call centre in Fort St. John to be approximately $834,521 (2012) compared to the existing call centre costs of approximately $667,911 allocated to PNG(NE) based upon the current allocation cost model, which was assessed and concluded to be reasonable earlier in this report. The establishment of a standalone call centre would represent an increase in annual operating costs of approximately $166,610 or 25% to PNG(NE).

Management notes that even if the actual annual operating costs and start-up costs were ultimately ±10-15% of the estimated annual and operating costs shown in Tables C and D, a standalone customer care facility would still be viewed as uneconomical.

C.3 Management’s Qualitative Assessment

Benefits of stand-alone call centre in Fort St. John.

1. A standalone facility may increase customer service and satisfaction levels with more dedicated staff which may be able to expand certain service offerings over time.

2. Synergies by opening a call centre in Fort St. John near its existing operating office in Fort St. John.

Challenges of stand-alone call centre in Fort St. John.

1. A new head office reporting package and call centre governance policies would be required to allow for proper oversight and governance of the operations of a new standalone facility.

2. Loss of synergies that currently exist between PNG’s Vancouver and Terrace offices as these offices provide supportive regulatory, accounting and administrative functions to all the PNG divisions.

56

3. The existing structure provides a call centre workforce that has cross functional service skills which are flexible to adapt to the needs of the existing call centre and also in support of the accounting function in the Terrace office. Creating a separate second standalone call centre has the effect of increasing overall labour and operating costs due to the higher levels of staffing and more extensive operations required to accommodate daily unforeseen operational challenges and variations on its own.

C.4 Management’s Conclusion – Standalone Customer Care Centre

Management is of the view that the creation of a new standalone customer care centre is not supportable economically at this time. Annual operating costs are expected to increase by 23%, with annual incremental costs to PNG on a consolidated basis being approximately $322,700. In addition, initial start-up costs will also be incurred in year 1 and are estimated to be in excess of $500,000.

Although there may be certain service and other benefits of a dedicated staff team and office in the PNG(N.E.) service area, these qualitative benefits do not outweigh the excessive incremental annual operating cost increases and initial start-up costs to PNG. Management views current customer satisfaction levels to be reasonable under its existing structure and is of the view that changes can be made within this structure to meet changing needs into the foreseeable future.

Evaluation of Overhead Capitalization Methodology Proposed By: Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd.

November 22, 2010

Table of Contents 1.0 Summary of Findings .................................................................................. 3

2.0 Purpose of the Report ................................................................................. 5

3.0 Background ................................................................................................. 8

4.0 Summary of PNG’s Proposed Overhead Capitalization Methodology ......... 9

5.0 KPMG Evaluation Approach ...................................................................... 11

6.0 Canadian Utilities Practices ....................................................................... 13

7.0 KPMG Findings ......................................................................................... 15

Appendix A – PNG’s 2010 Overhead Capitalization Study

Appendix B – Accounting and Regulatory Guidance A. Canadian Guidance B. International Guidance C. US Guidance D. Summary

Appendix C – References

Evaluation of PNG Overhead Capitalization Methodology

3

November 22, 2010

1.0 Summary of Findings

KPMG was retained by Pacific Northern Gas Ltd. to conduct an evaluation of Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd.’s (collectively “PNG” or the “Company”) overhead capitalization methodology for purposes of reporting to the British Columbia Utilities Commission (“the Commission”) as proposed in PNG’s 2010 Overhead Capitalization Study attached as Appendix A (the “PNG Study”).

No single regulatory guideline, statement or source exists that is universally accepted by utilities and regulators as the definitive statement, definition or standard that prescribes the types of overhead costs that should be considered for capitalization for purposes of regulatory and financial reporting. However, this topic has been the subject of discussion and comment and a body of evidence exists on the topic. From this evidence, a common principle arises:

That any assignment of indirect costs to a capital project should be done based upon some reasonable causal link or association with the capital activity.

PNG’s overhead capitalization methodology set out in the PNG Study is based on this principle.

KPMG finds that the PNG overhead capitalization methodology, presented herein to be a reasonable basis for the allocation of costs. This methodology is within the range of practice established by the external guidance (referred to in this evaluation) and observable capitalization allocation practices applied by Canadian utilities and utilities subject to the jurisdiction of the Commission (as observed through regulatory filings in various Canadian jurisdictions). Furthermore, the overhead capitalization methodology meets the criteria that PNG outline in Appendix C of their study. For additional analysis see section 7.0 KPMG Findings.

KPMG assessed PNG’s proposed overhead capitalization methodology in the context of 2009 actual results. It is PNG’s intention to apply this methodology commencing in 2011.

Table 1 below summarizes PNG’s estimates of the amount of Operations, Maintenance, Administration and General (‘O,M,A&G’) costs related to capital in both PNG and PNG (N.E.) using 2009 actual results for illustrative purposes.


4

November 22, 2010

Table 1 - Summary of Illustrative Capitalized Overhead Costs for 2009

Total Gross O,M,A&G

Total Capitalized Overhead

% of Total Gross O,M,A&G

Capitalized

PNG/PNG (N.E.) 2009 21,453,260 1,391,516 6.49%


5

November 22, 2010

2.0 Purpose of the Evaluation

Purpose KPMG was retained by PNG to conduct an evaluation of the overhead capitalization methodology proposed in the PNG report (attached as Appendix A). As noted earlier KPMG’s assessment relied on 2009 actual figures provided by management as 2010 actual figures were not yet available.

Specifically, KPMG was engaged to assess the reasonableness of:

• PNG’s proposed overhead capitalization methodology;

• the activities allocated to capital;

• the cost drivers; and

• the resulting overhead capitalization rate.

Report Structure Tables 2 and 3 below describe the sections and appendices in this report.


6

November 22, 2010

Table 2 – Report Body Section Descriptions

Section Description

1.0: Summary of Findings Includes a brief discussion of KPMG’s approach and summary of findings

2.0: Purpose of Report Outlines the structure of the report and provides a brief explanation of each section

3.0: Background Provides background on the reasons why PNG assessed their overhead capitalization methodology

4.0: Summary of PNG’s Proposed Overhead Capitalization Methodology

Provides a high level summary of the components of the overhead capitalization methodology

5.0: KPMG Evaluation Approach

Provides an explanation of KPMG’s approach to assessing PNG’s overhead capitalization methodology including the criteria used by KPMG during our analysis. This scope of the evaluation was agreed per the terms of the engagement letter between KPMG and PNG and the evaluation’s approach is based on KPMG’s past practice of similar overhead capitalization methodology studies undertaken by Canadian utility companies.

6.0: Comparison to Other Utilities

Provides a summary of the publicly available information KPMG used during our analysis of the overhead capitalization methodology

7.0: KPMG Findings Provides KPMG’s findings as to the reasonableness of the overhead capitalization methodology

Table 3 – Report Appendices Section Descriptions

Appendix Description

A: PNG’s 2010 Overhead Capitalization Study

Contains a detailed description of the approach and detailed criteria used by PNG to develop its proposed overhead capitalization methodology

B: Accounting and Regulatory Guidance.

Contains a description of guidance provided by accounting bodies and regulators

C: References Contains a description of the research


7

November 22, 2010

documents representative of PNG’s industry, which KPMG consulted to reach its findings

Scope Limitations Management responsibility: PNG’s capitalization methodology report is the responsibility of management who also maintain responsibility for the accuracy and completeness of the data and information associated with the overhead capitalization methodology and associated costs. KPMG engagement: Our engagement is to comment on the reasonableness of the overhead capitalization methodology and undertake the steps outlined in section 5.0 of this report. This evaluation does not constitute an audit of the overhead capitalization methodology, associated costs or capitalization rate. Accordingly, we do not express an opinion on such matters. For the avoidance of doubt, KPMG has neither audited nor reviewed the underlying O,M,A&G costs that form the basis of the percentages capitalized per PNG’s report attached as Appendix A to this report. KPMG assessed the proposed overhead capitalization methodology using 2009 actual figures, as provided by management, as 2010 actual figures were not yet available. Our findings and conclusions are therefore limited accordingly.


8

November 22, 2010

3.0 Background

In June 2010, PNG commenced preparation of the PNG Study as its overhead capitalization methodology had not been reviewed for several years. PNG will be applying the new methodology in the context of its 2011 revenue requirements application to the British Columbia Utilities Commission (“BCUC”). The Company will be transitioning from Canadian Generally Accepted Accounting Principles (“Canadian GAAP”) to International Financial Reporting Standards (“IFRS”) in the near future. IFRS is more restrictive than current accounting standards with respect to capitalization of capital overhead costs. PNG has considered IFRS requirements in its proposed methodology.

When the PNG Study was initiated, it was anticipated the Company would transition to IFRS effective January 1, 2011. However, in the intervening period the Canadian Accounting Standards Board approved an optional one year deferral of the mandatory date for first time adoption of IFRSs by entities with rate regulated activities. As such PNG now plans to defer its transition to IFRS to the year beginning January 1, 2012.

Despite the potential deferral, PNG intends to implement the overhead capitalization methodology proposed in the PNG Study effective 2011 to better align the Company’s capitalization methodology for overheads in anticipation of the future transition to IFRS.


9

November 22, 2010

4.0 Summary of PNG’s Proposed Overhead Capitalization Methodology

This section summarizes the key components of the overhead capitalization methodology proposed in the PNG Study.

In order to determine the overhead capitalization methodology, PNG first set out to update internal process and policy based on its consideration of a cross-section of current industry practices as observed through regulatory filings in various jurisdictions. Based on those developed policies, PNG:

• identified the activities that should be considered in its overhead capitalization calculations;

• identified drivers to be used to allocate the appropriate portion of cost directly to capital projects; and

• used 2009 data to model and test the overhead capitalization methodology.

Overhead Activities Allocated to Capital Table 4 below, which is an extract from Appendices H and K of the PNG Study, provides a summary of the categories of indirectly tracked capital activities that are proposed to be allocated to capital, as well as the drivers applied to each to determine the percentage of the related costs to be allocated to capital. Additional detail of the methodology and rationale for capitalization is described in Appendix I of the PNG Study.

Table 4 – Overhead Activities Allocated to Capital

Activity/Category Description Drivers

Field operations (operating and administration):

Support Field Employee Labour and Benefit Expense

• Estimated cost of staff time and associated benefit costs devoted to capital activities

• Apply estimated percentage of time on capital activities to identified staff labour and benefit costs


10

November 22, 2010

Activity/Category Description Drivers

Corporate (administration):

Management Salary and Benefit Expense


• Apply estimated percentage of time on capital activities to identified management salary and benefit costs

Benefits on Direct Labor :

Field Employee Benefit Expense

• Estimated field employee benefit costs as determined by a benefit load analysis

• Apply standard employee benefit load rate to field labour costs capitalized to specific capital projects

Warehouse and Shop Expense


• Apply estimated percentage of time on capital activities to identified warehouse and shop staff salary and benefit costs

Equipment Operating Expense

• Operating costs related to transportation and heavy work equipment used in capital projects (i.e., fuel, repairs, maintenance, insurance)

• Apply standard charge out rates to hours equipment utilized for specific capital projects

Equipment Depreciation Expense

(see Appendix K of PNG report)

• Depreciation expense related to transportation and heavy work equipment used in capital projects

• Apply standard charge out rates to hours equipment utilized for specific capital project


11

November 22, 2010

5.0 KPMG Evaluation Approach

This section summarizes KPMG’s approach to conducting our evaluation of PNG’s overhead capitalization methodology. Our work plan was developed in collaboration with PNG management in order to meet the objectives of this evaluation.

Our work plan incorporated the following steps:

• Step 1: Obtained an understanding of the proposed company policy and process documentation. In this step, KPMG obtained and reviewed relevant documentation relating to the allocation of overhead costs to capital at PNG in order to obtain an understanding of PNG’s overhead cost capitalization methodology.

• Step 2: Participated in interviews with company officials. In this step, KPMG participated in a workshop with PNG Finance staff and senior representatives from the operating areas. The purpose of this step was to gain an understanding of the specific activities and cost drivers within PNG that may be related to capital. This step also provided KPMG with a good understanding of PNG’s organizational structure and its approach to the acquisition, construction and installation of capital assets.

• Step 3: Summarized regulatory and accounting policy guidance researched by PNG and KPMG. In this step, KPMG summarized guidance provided by various accounting and regulatory authorities on the topic of overhead capitalization. A summary of the sources referenced by PNG can be found in the PNG Study (per Appendix B of PNG’s report). KPMG’s sources are identified in Appendix B of the KPMG report.

• Step 4: Assessed the reasonableness of PNG’s overhead capitalization methodology against external guidance. In this step, we assessed PNG’s methodology for overhead capitalization, as documented in the PNG Study, against external guidance collected and summarized in Step 3 and the practices of other Canadian utilities as observed through a study of regulatory filings in various jurisdictions.

• Step 5: Assessed the reasonableness of PNG’s overhead capitalization methodology against the internal criteria established by PNG. In this step, we assessed the alignment between PNG’s methodology against the criteria established by PNG.

• Step 6: Assessed the reasonableness of the activities included in the overhead capitalization methodology. In this step we assessed the activities resulting in capitalized costs (in accordance with the overhead capitalization methodology) against examples in internal policy


12

November 22, 2010

and external guidance summarized in Step 3, as well as those observed in the practices of other Canadian utilities.

• Step 7: Assessed the reasonableness of the drivers used to allocate overhead costs to capital. In this step we assessed the reasonableness of drivers used in the overhead capitalization methodology.

• Step 8: Assessed the reasonableness of the resulting overhead capitalization rate. In this step we assessed the reasonableness of the resulting overhead capitalization rate against a cross-section of current industry practices as observed through a study of regulatory filings in various jurisdictions.

• Step 9: Assessed the model used by PNG to calculate the overhead capitalization rate. In this step we assessed the methodology utilized in the model against PNG’s proposed and documented overhead capitalization methodology policy. We walked-through a number of items noted as capitalized costs back to source data, and validated a sample of 13 costs used in the overhead capitalization methodology against internal financial system reports.

• Step 10: Prepared report. In this step, KPMG prepared this report to summarize the results of the evaluation.


13

November 22, 2010

6.0 Canadian Utility Practices

KPMG obtained an understanding of other Canadian utility practices as observed through regulatory filings and regulator decisions.

The utilities considered are summarized in the Table 5 below.

Table 5 - Utility Research

Utility Jurisdiction Utility Jurisdiction

TGVI BCUC Hydro One OEB

TGI BCUC Fortis BC BCUC

BC Transmission Co BCUC EPCOR AUC

BC Hydro & Power Authority BCUC AltaGas AUC

Ottawa Hydro OEB ENMAX AUC

ENMAX AUC NB Power NBEUB

ATCO AUC Union Gas OEB

PUC Distribution OEB Fortis AB AUC

At present, based on the research of other Canadian utility practices, all the utility organizations report under Canadian GAAP. However, there is a relatively wide range of practices with respect to capitalizing overhead among utilities. This reflects the considerable judgment inherent in accounting and regulatory guidance.

The review of other Canadian utility practices revealed the following observations:

• Overhead capitalization methodologies vary greatly and many apply a percentage to a capital expenditure amount;

• Some utilities use a single allocation factor (i.e. % of total Operating, Maintenance, Administrative and General costs (OMA&G) vs. capital), while others use multiple allocators (i.e. labour time estimate, composite averages etc) specific for each activity;


14

November 22, 2010

• Some utilities apply fully-allocated capital overhead cost allocation methodologies which is to say that capitalized overhead costs include a share of the indirect and fixed costs that do not vary directly with the level of capital activity (i.e. administration and general expenses); while others utilize an incremental capital overhead cost allocation methodology where eligible costs are defined as those that would not exist if capital activity ceased; and

• There is little consistency with respect to what cost components were included in the overhead capitalization rate; costs ranged from shared services, distribution, gas supply and transmission, to general administration and overhead.

A detailed list of the reference sources KPMG consulted is provided in Appendix C.


15

November 22, 2010

7.0 KPMG Findings

KPMG finds that the PNG overhead capitalization methodology, presented herein to be a reasonable basis for the allocation of costs. This methodology is within the range of practice established by the external guidance (referred to in this evaluation) and observable capitalization allocation practices applied by Canadian utilities and utilities subject to the jurisdiction of the Commission (as observed through regulatory filings in various Canadian jurisdictions).

Steps 1 through 3 of the KPMG approach address the gathering of data in order to perform assessment in Steps 4 through 8 found below:

Reasonability of the Overhead Capitalization Methodology against External Guidance In Step 4 KPMG assessed the methodology PNG established in its policy for overhead capitalization against external guidance collected in Step 3 of section 5.0 and the practices of other Canadian utilities as observed through a study of regulatory filings in various jurisdictions.

Reasonability of the Overhead Capitalization Methodology against Internal Criteria Established by PNG

KPMG finds that the capitalization methodology used to be reasonable and within the range of practices represented by the external guidance summarized in Step 3 and a cross-section of current industry practices as observed through regulatory filings in various jurisdictions.

In Step 5 KPMG assessed PNG’s overhead capitalization methodology against PNG’s internal criteria.

Table 6 below summarizes KPMG’s assessment of PNG’s overhead capitalization methodology against PNG’s criteria set out in the PNG Study.


16

November 22, 2010

Table 6 - Evaluation of Overhead Capitalization Methodology

Key: S = satisfies the evaluation criteria SS = somewhat satisfies the evaluation criteria NS = does not satisfy the evaluation criteria


Defensible Cost Causation Linkage

S

• Internal policy provides guidance requiring a reasonable causal link or association with the capital activity for costs to be allocated to capital.

Distinguishable from Directly Allocated Capital Costs

S

• Overhead costs allocated using this methodology are costs specific to capital activities but not allocated to projects.

Transparency S

• The methodology relies on formal documentation at each step of the process. It thus addresses the criteria for transparency.

Freedom from Bias S

• PNG’s documented methodology and internal guidance in conjunction with PNG’s finance group review of management’s estimates, effectively safeguards the methodology from bias.

Stability S

• The methodology can be applied consistently year over year without resulting in major variances in amounts capitalized.


17

November 22, 2010


Accuracy of Underlying Data S

• KPMG was not engaged to conduct an audit or review of either the accuracy or completeness of the underlying O,M,A&G costs that form the basis of the percentages capitalized per PNG’s report attached as Appendix A to this report

• However, we assessed the methodology utilized in the model against PNG’s proposed and documented overhead capitalization methodology policy. We walked-through a number of items noted as capitalized costs back to source data, and validated a sample of 13 costs used in the overhead capitalization methodology against internal financial system reports.

• As detailed in the PNG Study, PNG undertook a detailed review of all non-direct employee time related to capital activities. The level of detail apparent in the data provided by management is significant which enhances reliability of the underlying data.

Flexibility / Adaptability S

• The overhead capitalization methodology and integrated Excel model facilitates updates, and thus supports the criteria.

Cost-Effectiveness • Low

implementation cost

S

• The overhead capitalization methodology requires limited time and effort for management to update. Additional time and effort was required in this iteration to understand the restrictions on activities eligible for allocation to capital under IFRS.

• The Excel model used to implement the methodology is straightforward and easily updated.


18

November 22, 2010


• Low on-going

costs S

• The capital cost allocation methodology requires limited time and effort for management to update.

• The Excel model requires little in the way of cost to maintain and update.

Reasonability of the Overhead Activities Allocated to Capital

KPMG finds that PNG’s proposed overhead capitalization methodology is reasonable as compared to PNG’s established criteria.

In Step 6 KPMG conducted a high level evaluation of the overhead activities allocated to capital against examples in internal policy and external guidance summarized in Step 3 of section 5.0

KPMG expects that PNG will evolve its overhead capitalization methodology, with respect to overhead activities allocated to capital, as clarity around IFRS guidance improves and the utility industry’s interpretation of IFRS guidance matures.

KPMG finds the overhead activities allocated to capital to be reasonable and within the range of guidance summarized in Step 3 of section 5.0 and observed in the practices of other Canadian utilities.

Reasonability of the Drivers Used to Allocate Costs to Capital In Step 7 KPMG assessed the reasonableness of the drivers used to allocate overhead costs to capital.

• Field Employee Benefit Expense load rate applied to labour cost charged to specific capital projects (benefit rate / hour).

KPMG assessed the method that PNG management utilized in order to determine the Field Employee Benefit Expense and to allocate labour cost directly charged to specific capital projects.

This driver was chosen as it most accurately reflects the key component of the overhead cost to be allocated to capital – labour benefit cost.

KPMG finds that the use of a Field Employee Benefit Expense load rate applied to labour cost charged to capital is reasonable


19

November 22, 2010

• Management and Support Field Employees Labour and Benefit Expense

KPMG assessed the labour-time estimate method that PNG management utilized in order to determine the amount of time spent by Management and Support Field Employees Labour and Benefit Expense on overhead activities related to capital.

This driver was chosen as it most accurately reflects the key component of the overhead cost to be allocated - labour.

• Equipment Operating Expense divided by hours used (operations and capital); multiplied by capital project hours (equipment operating hourly cost).

KPMG finds that the use of the labour time estimate to allocate Management and Support Field Employees Labour and Benefit Expense to capital is reasonable

KPMG assessed the method that PNG management utilized in order to determine the Equipment Operating hourly expense and to allocate cost to capital projects by hours spent on specific capital projects.

This driver was chosen as it most accurately reflects the key component of the overhead cost to be allocated to capital – equipment cost.

• Equipment Depreciation Expense divided by hours used (operations and capital); multiplied by capital project hours (equipment depreciation hourly cost).

KPMG finds that the use of the Equipment Operating Expense to allocate equipment related overhead costs to capital is reasonable

KPMG assessed the method that PNG management utilized in order to determine the Equipment Depreciation hourly expense and to allocate cost to capital projects by hours spent on specific capital projects.

This driver was chosen as it most accurately reflects the key component of the overhead cost to be allocated to capital – equipment depreciation cost.

KPMG finds that the use of Equipment Depreciation Expense to allocate equipment depreciation related overhead costs to capital is reasonable

Reasonability of the Capitalization Rate

In Step 8 KPMG compared the capital overhead rate estimated by PNG’s management to that applied by other Canadian utilities.


20

November 22, 2010

Our comments in this step are necessarily limited by our findings in Section 6 that the methodology followed by various members of the Canadian utilities industry varies widely. KPMG observed that generally, utilities in Canada (as observed through regulatory filings in various Canadian jurisdictions) historically capitalize 10 to 20 percent of gross OM&A costs; however some utilities capitalize fewer costs due to the nature of their businesses having relatively lower proportion of capital costs. Furthermore, KPMG observed that the utilities in Canada that have considered the IFRS guidelines when setting their overhead capitalization rate have determine their rates to be significantly lower than the historical levels mentioned above.

Table 7 summarizes the overhead capitalization rates recently proposed in GRA’s filed by or approved for BC utilities.

Table 7 – Comparative Overhead Capitalization Rates

* IFRS was not considered when setting the rate

** Source: regulatory filings

Several factors should be taken into consideration when comparing the above rates to PNG’s capitalization rate including changes resulting from the implementation of IFRS guidelines, the activities allocated to capital in those organizations and the overhead capitalization methodology they use. Due to the extended timeline for IFRS implementation, several of the examples above have not yet implemented IFRS and maintain higher rates than those companies that have already taken IFRS into consideration.

Although the rates observed vary widely, KPMG finds the capitalization rate estimated by PNG is within the range of rates observed by other utilities under the jurisdiction of the British Columbia Utilities Commission

.

Utility Jurisdiction Rate (**)

Terasen Inc. BCUC 8.17%

Terasen Vancouver Island Inc. BCUC 5.22%

Hydro BC & Power Authority* BCUC 19.1%

FortisBC* BCUC 20%


21

November 22, 2010

Reasonability of the Model Used by PNG to Calculate the Overhead Capitalization Rate In Step 9 KPMG assessed the methodology utilized in the model against PNG’s proposed and documented overhead capitalization methodology policy. We walked-through a number of items noted as capitalized costs back to source data, and validated a sample of 13 costs used in the overhead capitalization methodology against internal financial system reports.

KPMG finds the PNG model used to be consistent with the overhead capitalization methodologies as proposed and documented within PNG’s overhead capitalization methodology policy. The items used in our walk-through were consistently reflected in the model and the underlying financial system reports.

Appendix A – PNG’s 2010 Overhead Capitalization Study

Pacific Northern Gas Ltd. and Pacific Northern Gas (N.E.) Ltd. 2010 Overhead Capitalization Study

November 2010


2 of 33

Table of Contents Background ................................................................................................................................... 3 Basis for Study .............................................................................................................................. 4 Study Approach ............................................................................................................................. 5 Summary of Key Findings ............................................................................................................. 7 Comparison of Overhead Capitalization under Proposed and Current Methodologies ............... 8 APPENDICIES APPENDIX A – Current Capitalization Policies and Practices ................................................ 10

APPENDIX B – Accounting and Regulatory Policy Guidance ................................................ 12

APPENDIX C – Overhead Capitalization Evaluation Criteria.................................................. 15

APPENDIX D – Budget Centre Input ....................................................................................... 16

APPENDIX E – Interview Background and Questionnaire ...................................................... 17

APPENDIX F – Overhead Capitalization Criteria .................................................................... 19

APPENDIX G – Budget Centre Interview Summary ............................................................... 21

APPENDIX H – Evaluation of Costs for Inclusion in Overhead Capitalization ....................... 26

APPENDIX I – Summary of Overhead Allocation Methodology ............................................. 28

APPENDIX J – Comparison of Proposed vs Current Allocation Using 2009 Figures ............ 30

APPENDIX K – Revisions to Capitalization Methodology for Depreciation ............................ 33


3 of 33

Background Pacific Northern Gas Ltd. and its wholly-owned subsidiary, Pacific Northern Gas (N.E.) Ltd. (collectively “PNG” or “the Company”), operate over 3,500 kilometers of natural gas transmission and distribution pipeline and serve a base of more than 39,000 residential, commercial and industrial customers located in northern British Columbia. The Company has established two operating divisions, PNG-West, which generally includes the assets of the parent company, and PNG (N.E.), which generally includes the assets of the subsidiary company and is comprised of three sub-divisions, Fort St. John (“FSJ”), Dawson Creek (“DC”) and Tumbler Ridge (“TR”). The Company’s activities are regulated by the British Columbia Utilities Commission (“BCUC”), with three separate revenue requirements applications being filed for consideration and approval based on operating area, including the PNG-West region, DC/FSJ and TR. PNG’s capital spending program to upgrade and maintain its capital assets is a major focus for the utility in terms of time and cost. Direct spending on capital projects for 2010 is estimated to be approximately $8 million, representing close to 4.5% of the net book value of property, plant and equipment as at December 31, 2009. PNG’s capital program requires significant support from all areas of the utility, including engineering, management, administration and infrastructure resources. These resources support both the operating activities and capital works projects carried out by the Company, and in many cases cannot be directly attributable to a specific capital project. Historically, PNG has allocated costs associated with these support activities to capital projects by means of a capital overhead allocation methodology that applied various cost drivers to a defined pool of costs.


4 of 33

Basis for Study In June 2010, PNG commenced a study of its capital overhead allocation methodology. The basis for this study was two-fold:

1) A study has not been completed for some time. This study will serve as the basis for the Company’s new overhead capitalization methodology to be implemented in its 2011 revenue requirements applications; and

2) The Company will be transitioning from Canadian Generally Accepted Accounting

Principles (“Canadian GAAP”) to International Financial Reporting Standards (“IFRS”) in the near future. IFRS is more restrictive than current accounting standards with respect to capitalization of overhead costs. This study proposes changes that align PNG’s capitalization overhead methodology with IFRS requirements in this area.

When this study was initiated, it was anticipated the Company would transition to IFRS effective January 1, 2011. However, in the intervening period the Canadian Accounting Standards Board announced an optional one-year deferral for regulated entities, postponing the transition to IFRS to January 1, 2012. The Company has made the decision to take the one-year deferral on this transition. Despite this deferral, the changes in capital overhead allocation methodology identified in this study are proposed for implementation effective 2011 to align the Company’s accounting treatment in anticipation of the future transition to IFRS.

This study summarizes the approach used by PNG to complete its internal review and proposes a new capital overhead allocation methodology to be used on a go-forward basis. Fiscal 2009 operating results have been used as the base year for the financial analysis presented in this study.


5 of 33

Study Approach PNG’s approach to this study incorporated the following steps: • Step 1: Document existing approach for capitalization of overhead costs. In this

step, PNG finance staff reviewed and summarized the existing processes and procedures for capitalization of costs, including overheads, to provide a context for this study. The current methodology is summarized in Appendix A.

• Step 2: Planning session with Company management. In this step, PNG finance staff

met with senior representatives from finance and field operations to discuss the project and to gain an understanding of those activities that appear to support, either directly or indirectly, capital projects at PNG. The purpose of this step was to identify specific activities within PNG that may be eligible to have costs allocated to capitalized overhead. Based on this activity, the decision was made to evaluate all budget centres as part of this project.

• Step 3: Document regulatory and accounting policy guidance. In this step, PNG

researched guidance provided by various accounting and regulatory authorities on the topic of overhead capitalization. The objective of this step was to ensure that PNG’s capital overhead allocation methodology was consistent with a cross-section of current industry standards and practices. A summary of the external guidance is provided in Appendix B.

• Step 4: Develop criteria for the capital overhead allocation methodology. Based on

the initial steps above, PNG developed a set of criteria to be used to evaluate its methodology for estimating the amount of overhead costs associated with capital projects. A summary of the evaluation criteria is included as Appendix C.

• Step 5: Budget centre interviews and discussion. Appendix D provides a summary of

budget centres included in this study. In this step PNG finance staff interviewed management of budget centres using standardized questionnaires to gain an understanding of budget centre activities that may be directly or indirectly related to the Company’s capital projects. Information provided to interviewees in advance of scheduled meetings is included as Appendix E. As supporting documentation for these interviews, the following information was compiled: – A written description of the activities performed by the budget centre, including

specific activities that directly or indirectly support capital projects; – Estimates of the percentage of budget centre management’s time related to capital

activities budgeted for 2010; and – An indication as to whether there would be a reduction in human resources should all

capital projects be discontinued. • Step 6: Document PNG’s capital overhead capitalization criteria. In this step, based

on background research and budget centre interviews and discussion, PNG prepared a statement that summarizes PNG’s guidelines for overhead capitalization. This statement is included as Appendix F.


6 of 33

• Step 7: Internal survey results. In this step PNG finance staff reviewed and summarized data collected from all relevant departments, noting costs to be included in the new overhead allocation methodology. This information is provided in Appendix G.

• Step 8: Evaluation of costs. In this step PNG finance staff evaluated and summarized indirect costs to be capitalized. Appendix H provides a summary of costs identified for capitalization. Appendix J discusses costs historically capitalized as compared to those proposed for capitalization under the new methodology.

• Step 9: Develop new overhead allocation methodology. In this step, PNG developed the proposed new overhead allocation methodology using 2009 actual financial information and the activities data obtained through the Step 5 interview process and as summarized in Step 8 above, including the percentage of time spent on capital activities. A common methodology is proposed for application at the divisional level, using cost and activity date for each division filing regulatory rate applications. The processes underlying the new overhead allocation methodology are summarized in Appendix I.

• Step 10: Write Study. This step involved the writing of this report to document the

process and results of the Company’s internal review. Appendix J provides a comparison of how the proposed new overhead allocation methodology differs quantitatively from the current overhead allocation methodology.

• Step 11: Proposed Revisions to Depreciation Capitalization. An additional matter of

note is that the capitalization of depreciation expense was also examined a part of this study. This step involved preparing a summary of the current process, the changes proposed to this methodology, and the financial effects of the proposed changes as documented in Appendix K.


7 of 33

Summary of Key Findings Based on the study undertaken, the following views have been incorporated into PNG’s capital overhead allocation methodology: 1) Upon transition to IFRS, it is anticipated that IFRS capitalization methodology for

overheads will be better aligned for ratemaking and regulatory reporting purposes. • Implementation of the new overhead allocation methodology in the interim period will

align the Company’s capitalization approach with the more restrictive IFRS requirements for capitalized overhead.

• Harmonized treatment will avoid the requirement for a transactional two-ledger accounting, planning and reporting system with added cost and confusion that such systems would entail.

• This aligns with other Canadian regulatory jurisdictions (Ontario and Alberta) which will require utilities to adhere to IFRS capitalization accounting requirements on transition to IFRS.

2) Capitalized overhead costs are to reflect only those overhead costs that meet the

definition of “directly attributable” as per the capitalization criteria presented in Appendix F. Specifically, these costs would include: • Field operations employee wages related to non-project-specific capital support and

oversight (operations accounting and warehouse activities) directly related, or incremental to, capital projects;

• Field operations management and corporate management salaries related to non-project-specific capital support and oversight directly related, or incremental to, capital projects; and

• Employment benefit costs associated with employee wages and management salaries charged to capital projects.

3) Employee benefit costs are to be incorporated into the capital overhead allocation

methodology. • Employee benefit costs will be allocated to capital projects via the development and

analysis of forecast employee benefit load rates that will be applied to capitalized wages and salaries.

4) A proportionate share of operating costs associated with vehicles and equipment

involved in capital projects are to be allocated to capital projects. • Costs will be allocated to capital projects on a pro rata basis using the historic

percentage of equipment hours utilized for capital projects as a proportion of total equipment hours, with a periodic true-up to the actual capital utilization rate.

• All vehicle and equipment operating costs will be subject to allocation, including related insurance costs.


8 of 33

Comparison of Overhead Capitalization under Proposed and Current Methodologies Overhead Capitalization Under the proposed methodology, a detailed analysis of individual cost elements has been undertaken to determine amounts appropriate for capitalization. In addition, a detailed review of budget centre activity was also conducted to identify the appropriate percentage of costs to be capitalized. A comparison of overhead amounts to be capitalized under the proposed new methodology based and the current methodology is provided in the tables below using 2009 figures for illustrative purposes. In addition to the overall impacts, information is provided on a disaggregated basis to reflect the impacts for each operating division for which a separate rate application is filed. The percentage amounts capitalized as overhead is illustrative only and represents the total overhead capitalized divided by total operating, maintenance, administrative and general costs (“O,M,A&G”). The dollar figure for overhead capitalized is determined by application of the overhead capitalization methodology and not by application of this resultant percentage.

Overall PNG (West)2009 2009 2009 2009

Capitalized Overhead Element Proposed Current Proposed CurrentMethodology Methodology Change Methodology Methodology Change

1) Capitalization of general overhead costsField Operations (Operating and Administration) 415,295 754,984 (339,689) 382,266 539,304 (157,038) Corporate (Administration) 129,144 1,096,955 (967,811) 129,144 885,194 (756,050) Benefits on Direct Labour 552,507 - 552,507 378,088 - 378,088

1,096,946 1,851,939 (754,993) 889,498 1,424,498 (535,000)

2) Capitalization of warehouse and shop expenditures 64,287 89,650 (25,363) 64,287 58,635 5,652

3) Capitalization of equipment operating expenditures 230,283 260,754 (30,471) 161,908 192,004 (30,096)

4) Capitalization of unallocated capital - 90,541 (90,541) - 75,987 (75,987)

Total Overheads Capitalized 1,391,516 2,292,884 (901,368) 1,115,693 1,751,124 (635,431)

Gross Operating, Maintenance, Administrative & General Costs 21,453,260 21,453,260 14,345,638 14,345,638

Percentage of Operating, Maintenance, Administrative and General Costs 6.49% 10.69% 7.78% 12.21%

DC / FSJ TR2009 2009 2009 2009

Capitalized Overhead Element Proposed Current Proposed CurrentMethodology Methodology Change Methodology Methodology Change

1) Capitalization of general overhead costsField Operations (Operating and Administration) 29,726 211,641 (181,915) 3,303 4,039 (736) Corporate (Administration) - 208,111 (208,111) - 3,650 (3,650) Benefits on Direct Labour 166,299 - 166,299 8,120 - 8,120

196,025 419,752 (223,727) 11,423 7,689 3,734

2) Capitalization of warehouse and shop expenditures - 31,015 (31,015) - - -

3) Capitalization of equipment operating expenditures 66,703 67,027 (324) 1,672 1,723 (51)

4) Capitalization of unallocated capital - 14,554 (14,554) - - -

Total Overheads Capitalized 262,728 532,348 (269,620) 13,095 9,412 3,683

Gross Operating, Maintenance, Administrative & General Costs 6,115,025 6,115,025 992,597 992,597

Percentage of Operating, Maintenance, Administrative and General Costs 4.30% 8.71% 1.32% 0.95%


9 of 33

As per the first table above, on an overall basis, illustrative amounts for 2009 indicate that overheads capitalized under the proposed methodology would be $1,391,516 or 6.49% of gross O,M,A&G costs, compared to $2,292,884 or 10.69% of gross O,M,A&G costs under the current methodology. A detailed analysis of items contributing to the decrease is provided in Appendix J. The decrease in amounts capitalized is as anticipated given adherence to the more restrictive IFRS guidance which specifically excludes certain costs from capitalization, including those related to safety and training, project investigation and approval, and general administrative activities. Management judgment has been applied in identifying activities and costs to be included in the proposed overhead capitalization methodology. Costs identified for capitalization in the proposed methodology are subject to audit for compliance with IFRS capitalization requirements.


10 of 33

Appendix A – Current Capitalization Policies and Practices PNG has an annual budget process that involves the preparation of separate capital and operations, maintenance and administration budgets for the upcoming fiscal period for each budget centre within the organization. Capital Budgeting Specific projects are identified and included within capital budgets prepared by responsible budget centres. Capital budgets are created using a bottom-up approach on a cost element basis. Once approved, an Authority For Expenditure (“AFE”) is raised and a specific project identification number is assigned to the project. This identification number is used as the basis for assigning all costs directly attributable to the project as they are incurred – this includes labour and materials costs. Operations, Maintenance, Administration & General Budgeting Responsible budget centres also prepare O,M,A&G budgets. Prior year budgets provide the basis for individual expense items to be included and accounted for in this process. O,M,A&G expenditures are generally budgeted based on the function and nature of the expenditures, including: Operating Costs Transmission Distribution General Sales Billing

Maintenance Costs Transmission Distribution Processing General

Administrative/General Costs

The build-up of these amounts reflect the roll-up of amounts budgeted in detail based on BCUC account codes and, in further detail, based on cost elements. Capitalization of Indirect Costs PNG’s current approach to the capitalization of costs not directly charged to capital projects has four distinct streams: 1) Capitalization of general overhead

PNG presently includes certain O,M,A&G expenditures in amounts allocated to capital projects as general capital overheads. Specifically, a percentage of amounts recorded as general operating costs under system operations, safety, training, allowed time off without pay, vacation and shorter work year leave benefits are capitalized, as is a percentage of amounts recorded as administration costs under administration and employee benefits. Historically, amounts have been capitalized at BCUC-approved rates that have been updated annually based on the percentage of labour costs budgeted for capital projects relative to total budgeted labour costs (total budgeted labour costs = field labour costs budgeted for direct capital + field labour costs budgeted for O,M,A&G). The rationale for this allocation methodology is that overhead costs have been budgeted for capital/non-capital activities in direct proportion to field labour costs budgeted for these activities. For reference, actual general overhead capitalized in 2009 were $1,851,939. Appendix J includes a summary of amounts included in the capitalization of general overhead.


11 of 33

2) Capitalization of warehouse and shop expenditures On the premise that the warehouse and shop operate predominantly to support capital projects, the costs associated with these activities are allocated to capital projects. These costs are allocated amongst individual capital projects based on labour hours worked on a project as a proportion of total labour hours spent on all capital projects in the year. For reference, actual warehouse and shop expenditures capitalized in 2009 were $89,650.

3) Capitalization of equipment operating expenditures

Vehicle and equipment operating costs are captured via invoices, VISA card summaries, employee expense claims and payroll reporting (for time spent on repairs and maintenance of vehicles). Costs are allocated to capital projects and O,M,A&G by applying the number of hours the equipment is used for a specific project (based on time of employee operating equipment as captured by payroll reporting) to standard equipment charge-out rates set on a periodic basis based on operating costs incurred and total hours the equipment has been charged out in previous periods. Variances from standard over (under) allocated at the end of the period are cleared to capital projects at the end of each month. For reference, actual equipment operating expenditures allocated to capital projects in 2009 were $260,754.

4) Capitalization of “unallocated” capital

During the course of the year, field operations incur costs identified as capital expenditures but are not specifically attributable to a particular individual project. These costs are accumulated in a balance sheet account called unallocated capital. These costs are allocated amongst individual capital projects based on labour hours worked on a project as a proportion of total labour hours spent on all capital projects in the year. For reference, actual “unallocated capital” capitalized in 2009 was $90,541.


12 of 33

Appendix B – Accounting and Regulatory Policy Guidance The following is a summary of guidance provided by accounting and regulatory authorities on the topic of overhead capitalization. This information has been gathered and reviewed to ensure that PNG’s proposed capital overhead allocation methodology is consistent with a cross-section of current accounting standards and industry practices. Based on the review of relevant guidance, aligning current accounting treatment for overhead capitalization with the more restrictive provisions of IFRS would not be considered a change in accounting policy, as the underlying policy of capitalizing overhead remains unchanged. The proposed methodology is a change in accounting estimate of amounts to be capitalized as part of the cost of property, plant and equipment to be applied on a prospective basis. Accounting Guidance

The Canadian transition to International Financial Reporting Standards (IFRS) for most entities is to be effective January 1, 2011. However, in September 2010 the Canadian Accounting Standards Board announced an optional one-year deferral for rate-regulated entities, allowing for the postponement of the transition to IFRS for these entities to January 1, 2012.

Accounting Standards

The Company has made the decision to take this optional deferral and is required to comply with Canadian GAAP in effect pre-IFRS (prior to the financial year commencing January 1, 2011) for the intervening period. Despite this deferral, the Company’s intent is to align its accounting treatment of capital overheads with IFRS requirements in anticipation of the future transition to IFRS. Relevant guidance on accounting for capital assets under Canadian GAAP is provided in the Canadian Institute of Chartered Accountant’s “Handbook Section 3061: Property, Plant and Equipment”. Section 3061 (par 20) states that the cost of an item of property, plant and equipment includes direct construction or development costs (such as material and labour), and overhead costs directly attributable to the construction or development activity. This guidance is general in nature and open to judgment in application. Under IFRS, guidance on accounting for capital assets, including the capitalization of overhead, is governed by International Accounting Standard 16, Property, Plant and Equipment (IAS 16). IAS 16 states that the cost of an item of property, plant and equipment comprises:

(a) its purchase price, including import duties and non-refundable purchase taxes, after deducting trade discounts and rebates;

(b) any costs directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by management; and

(c) the initial estimate of the costs of dismantling and removing the item. IAS 16 is more prescriptive than guidance under Canadian GAAP in that it provides examples of “directly attributable” costs, including:

(a) costs of employee benefits (as defined in IAS 19 Employee Benefits) arising directly from the construction or acquisition of the item of property, plant and equipment;

(b) costs of site preparation; (c) initial delivery and handling costs; (d) installation and assembly costs; (e) costs of testing whether the asset is functioning properly, and


13 of 33

(f) professional fees. IAS 16 also provides examples of costs that are not to be capitalized as part of an item of property, plant and equipment, including:

(a) costs of opening a new facility; (b) costs of introducing a new product or service (including costs of advertising and

promotional activities); (c) costs of conducting business in a new location or with a new class of customer (including

costs of staff training); and (d) administration and other general overhead costs.

Additional guidance on the issue of capitalization of directly attributable costs under IFRS is provided by international accounting firm, Deloitte, in their publication “iGAAP: IFRS for Canada”. In this publication, Deloitte suggests that costs that are directly incremental as a result of the construction of a specific asset can be considered to be directly attributable if they relate to bringing the asset to working condition. Deloitte goes on to say that where an entity regularly constructs assets it is possible that some element of apparently ‘fixed’ costs may also be directly attributable. In such circumstances, it may be helpful to consider which costs would have been avoided if none of those assets had been constructed (7:4.2.2).

Accounting Firms

Guidance under IFRS is also provided by international accounting firm, PricewaterhouseCoopers, in their “IFRS Manual of Accounting”, where they suggest as a general rule for overhead capitalization only incremental costs that would have been avoided had the asset not been constructed can really be directly and conclusively attributed to bringing the asset to its working condition. Regulatory Guidance In anticipation of the transition to IFRS, certain Canadian regulatory agencies have published accounting rules and comment papers to assist regulated entities with various issues pertaining to the transition. The following summarizes the positions of the Alberta Utilities Commission (AUC) and the Ontario Energy Board (OEB) on the matter of overhead capitalization:

AUC Rule 026 – 6(2(b)) – Capitalization/Non-Capitalization of Costs: General and Administrative Overhead (IAS 16.16 and 16.19(d))

Alberta Utilities Commission

Utilities shall adhere to the IFRS requirements for capitalization of costs that are not directly attributable to an asset.* Any financial difference that arises as a result of the adoption of IFRS requirements is to be identified in a Utility’s First IFRS-Compliant GRA/GTA, and the Utility shall also propose in that rate application the method for settling the difference**. In addition, the Utility will file a copy of its updated capitalization policy as a part of its First IFRS-Compliant GRA/GTA***. * IFRS does not allow the capitalization of costs that are not ‘directly attributable’ to the asset. ** For example, the establishment of a regulatory asset or liability. *** This request would be subject to review by the AUC and interested parties as part of the AUC’s decision making process.


14 of 33

EB 2008-0408 – Transition to International Financial Reporting Standards – Issue 3.3 Capitalization

Ontario Energy Board

The Board will require utilities to adhere to IFRS capitalization accounting requirements for rate making and regulatory reporting purposes after the date of adoption of IFRS. The utility will file a copy of its capitalization policy, identifying any updates to the policy, as part of its first cost of service rate filing after IFRS adoption. Revenue requirement impacts of any change in capitalization policy must be specifically and separately quantified.

Clarification of Accounting for Overhead Costs Associated for Capital Work (Feb 24 2010) As stated in the Board Report at Issue 3.3, the Board is requiring full compliance with IFRS requirements (eg. IAS 16) as applicable to non-regulated enterprises and only where the Board authorizes specific alternative treatment for regulatory purposes is alternative treatment acceptable. Based on IFRS consultations EB-2008-0104/0408 survey results this may mean a reduction in capitalized overhead for some electric utility distributors that have previously capitalized administration and other general overhead costs no longer permitted under IFRS. It may mean an increase for those that have capitalized little or no overhead costs in the past.


15 of 33

Appendix C – Overhead Capitalization Evaluation Criteria Methodologies for overhead capitalization address a set of formal, objective criteria that speak to company and policy objectives. In consideration of regulatory and accounting policy guidance presented in Appendix B, PNG has established the following criteria for its capital overhead allocation methodology: • Defensible Cost Causation Linkage. To conform to accounting guidelines, the methodology

should show a direct causal link between capitalized overhead and capital activity. • Distinguishable from Directly Allocated Capital Costs. The overhead costs must be

distinguished from those that are directly charged to capital. • Transparency. The methodology and calculations should be easy to follow and to

understand by internal users and by external observers (i.e. regulators). This will facilitate acceptance of the methodology.

• Freedom from Bias. The methodology should not tend to allocate an undue proportion of

costs toward either operating or capital activities. • Stability. The methodology should not result in disproportionately large variations in the

amounts of capitalized overhead from year-to-year. • Accuracy of Underlying Data. Any data used in the methodology should be accurate and

able to be relied upon. The data should provide an appropriate measure of the underlying volume of activity or output.

• Flexibility/Adaptability. The methodology should accommodate changes in organizational

structure, business processes, and information systems with reasonable ease. Thus, the methodology should be dynamic: it should be relatively easy to update and keep current as the organization evolves. To the extent possible, it should automatically adjust for changes in circumstance.

• Cost-effectiveness. In evaluating different methodologies, PNG should ensure that they are

cost-effective to implement. Additional accuracy may require significant additional cost, and thus an appropriate balance is required between precision and cost. In evaluating cost-effectiveness, two different perspectives are relevant:

• Low implementation cost. All else being equal, the methodology should be capable of

being implemented at a reasonable cost. • Low on-going costs. The methodology should have relatively low costs of upkeep.

Further, it should reduce the administrative, recordkeeping and reporting burden imposed on operating staff. The methodology should also integrate easily with the process used to prepare the Company’s financial statements.


16 of 33

Appendix D – Budget Centre Input The input of all budget centre managers has been sought for this study. While some departments may not have a direct connection to capital activities, the decision to include all departments in the review process was made to ensure completeness of the study.

Area Budget Centre Description Indicative Headcount

PNG-West 100 Regional Operations 63 200 Customer Service 16 300 Marketing & Lands 1 410 Operations Accounting 6 420 Customer Care 13 500 Community Relations & Admin 1 600 Construction Maintenance 15 700 Technical Services 7 720 Technical Services – Warehouse 1 800 Engineering and Special Projects 2 PNG (N.E.) 9X1 Regional Operations 26 Head Office 90 President & CEO 7 88 Human Resources 2 89/91/92 Operations & Engineering 3 93/99/900 Finance 10 94/96 Regulatory Affairs 2 095/798 Corp. Develop., Treasury & IT 5 97 Information Technology 3


17 of 33

Appendix E – Interview Background and Questionnaire The interview process was initiated with the circulation of the following background information on the project along with pre-established questions in the form of the questionnaire replicated below. In addition, summary financial information for the relevant budget centre was provided as a reference point in the discussion. Telephone and in-person interviews were subsequently held to discuss the process and go through the questionnaires. Background PNG has made a significant investment in property, plant and equipment to serve its customer base. The ongoing capital spending program to upgrade and maintain these assets is a major focus for the Company in terms of time and cost. Direct spending on capital projects for 2010 is estimated to be approximately $8 million, representing 4.5% of the net book value of property, plant and equipment as at December 31, 2009. PNG’s capital program requires significant support from all areas of the utility, including engineering, management, administration and infrastructure resources. These resources support both the operating activities and capital works projects carried out by the Company, and in many cases cannot be directly attributable to a specific capital project. As allowed under its regulatory model and current Canadian accounting standards, PNG has developed a capital overhead allocation methodology to allocate certain overhead costs to capital projects. This methodology applies various cost drivers (i.e. labour hours spent on capital project as a percentage of total labour hours) to an identified pool of overhead costs (i.e. supervisory time, employee benefits) as a means of allocating these costs to capital projects. Reason for Current Study PNG has commenced a review and update to its capital overhead allocation methodology. The basis for this initiative is two-fold:

1) An update has not been completed for some time. The updated review will serve as the basis for the Company’s overhead capitalization policy to be filed with the British Columbia Utilities Commission (“BCUC”) for regulatory purposes; and

2) The Company is transitioning from Canadian accounting standards to International

Financial Reporting Standards (“IFRS”) effective January 1, 2011, and IFRS are more restrictive than current accounting standards with respect to capitalization of overhead costs.

Required Assistance To assist with the study, we are undertaking interviews with senior representatives from each department to understand and identify those activities that appear to support, either directly or indirectly, capital projects at PNG. The purpose of this step is to gain an understanding of the specific activities within PNG that may be eligible to have costs allocated to capitalized overhead.


18 of 33

Outputs from this activity will be: a list of budget centers to be included in the cost allocation methodology; a description of specific activities within budget centres that support capital projects; estimates of the percentage of the 2010 and 2011 budgeted cost of activities that should

be allocated to capitalized overhead; and recommendations with respect to the basis for allocating these costs.

This project will be an iterative process:

The results of the interview will be summarized; Preliminary financial analysis will be undertaken; and This information will then be circulated back for your review and comment.

Questionnaire

Human Resources Self X Mgmt Reports X Other FTEs X Total X

1) Please describe the activities for this Budget Centre. 2) Please describe the capital activities that are directly charged to capital projects by this

Budget Centre. 3) Please describe the process by which these costs are charged directly to capital projects.

Do you think this approach is reasonable/appropriate? How could it be improved? 4) Please describe activities of this Budget Centre that might be considered to indirectly relate to

capital projects.

What would be an appropriate basis on which to allocate these costs to capital projects? (i.e. proportion of time spent, proportion of total dollars spent, by geographic cost centre, percentage of fleet) Approximately what percentage of the Budget Centre’s management time is spent on indirect capital activities?

Individual High (%) Low (%) Average (%) Name X% X% X%

5) Would your Budget Centre operate with fewer staff if the Company ceased to undertake all

capital projects? If so, how many and why?


19 of 33

Appendix F – Overhead Capitalization Criteria Internal Guidelines Accounting and regulatory guidance (Appendix B) with respect to capitalization of overheads is general in nature. PNG has prepared its own internal guidelines to provide more specific direction as to the nature, type, and quantum of costs that should be included in costs to be capitalized. The definition of capitalized overhead that has been adopted for this study is as follows:

Those items that are directly attributable to bringing the capital asset to the "location and condition necessary for its intended use" should be recognized as a capital cost. In addition to costs charged directly to the capital asset, other costs which are directly attributable to bringing the assets to their location and condition necessary for intended use but are not directly charged to the asset should be allocated to the asset cost.

Capitalized Overhead

Overheads capitalized represent a reasonable and appropriate amount of costs that are directly linked to capital activity (new assets acquired or constructed) but, due to the onerous nature of capturing these costs, are not directly assigned to individual capital projects. In order to qualify as capitalized overhead:

o there must be an established causal link or association of these costs with capital activity;

o these overhead costs must be distinguished from those that are directly charged to capital.

Based on these criteria, overheads capitalized would include incremental costs associated with non-project specific capital support and oversight of activities directly related to capital projects.

Overhead Capital Activities Activities that have costs to be included in capitalized overhead generally fall into one of the three categories noted below. While the boundaries between these types of activities are not always clear, the categories do help to provide a conceptual framework to help identify and evaluate those costs eligible for capitalized overhead: 1. Costs Specific to Capital Support but Not Allocated to Projects

This includes formulating, evaluating, initiating, designing, approving and implementing capital additions. These costs are captured in capitalized overhead because: o These functions relate to many capital projects rather than specific or identified ones; and o It is impractical to capture costs directly to specific capital projects. An example of this would be the capital budgeting and capital risk assessment processes of ongoing capital projects.


20 of 33

2. Oversight of Activities Directly Related to Capital Projects but Not Allocated to Projects These costs include the direct supervision, cost control and reporting that are in direct support of capital projects. An example of this would be the supervision of construction departments.

3. Support Functions and Infrastructure This category covers the support functions and infrastructure networks that enable departments that are directly involved in performing capital work. An example of this would be found in the areas of Human Resources and IT.

Nature of Capitalized Overhead Costs considered for inclusion in capitalized overhead can be distinguished from:

• Costs charged directly to capital. These are costs that are charged directly to capital projects and that therefore form part of the direct capital cost of the associated assets. Such costs include the costs of materials and construction labour, as well as any purchased services (e.g. outside contracting) that may be associated with installation of the asset.

• Operating, maintenance, administrative and general expenses. These costs appear in the income statement for PNG in the period concerned. These costs include any costs that are not identified as being related to capital projects. They thus encompass a wide range of costs, including costs associated with customer billing and service, most administrative and general costs, and costs associated with maintenance activities.

Capitalized overhead, in contrast to the cost elements above, reflects those costs that relate to capital projects but that have not been specifically identified with any individual capital project.


21 of 33

Appendix G – Budget Centre Interview Summary The following table summarizes budget centres activities related to capital projects as identified in the study interview process, as well as the estimated time that management spends on capital-related activities, and an assessment of the appropriateness for capitalization of the costs associated with such activities.

Budget Centre Activities related to capital projects

Management’s estimate of their time spent on capital

activities Assessment of Appropriateness

for Capitalization Low High Average

100 – Regional Operations (West)

Direct: None 20.0% 30.0% 25.0% Capital Overhead Management time on capital activities is considered to be incremental to capital projects

Indirect: Management time on: annual capital plans; annual capital risk assessment; AFE review and monitoring; and unexpected events requiring evaluation and subsequent capital expenditures

200 – Customer Service

Direct: None 5.0% 10.0% 7.5% Not Capital As costs are generally recovered, management time is not considered to be incremental to capital projects

Indirect: Management involvement in third-party requests (i.e. main alterations); costs are generally recovered from third parties

300 – Marketing & Lands

Direct: None 35.0% 40.0% 37.5% Capital Overhead Management time on capital activities is considered to be incremental to capital projects

Indirect: Considerable time spent in support of construction maintenance, including: management and administration of applications and permits required for new capital projects and upgrades to existing plant; coordination of Hearing of Intent process with Oil & Gas Commission for capital projects; coordination of notification to landowners


22 of 33





affected by capital projects

410 – Operations Accounting

Direct: AP clerk has first aid certification and occasionally provides first aid services to construction projects; time spent on this activity is charged direct to capital

10.0% 20.0% 15.0% Capital Overhead Nature of activities identified as being indirectly related to capital projects for this budget centre are incremental to capital activities; time devoted to these activities would be freed up if capital activities ceased, potentially eliminating one FTE staff position.

Indirect: Entry, processing and review of AP, payroll and equipment costing entries for capital transactions; setting up and closing capital projects; review, analysis and reporting on capital AFEs; consolidation/ review of capital field budgets; review of purchasing and inventory transactions for capital

420 – Customer Care

Direct: None 0.0% 10.0% 5.0% Not Capital Activities in themselves are not capital in nature as budget centre capital projects are generally purchased systems, not developed in-house; time involved would be for scoping requirements, training, etc.

Indirect: Occasionally time might be required on customer-service related capital projects (i.e. new phone system)

500 – Community Relations and Administration

Direct: None 10.0% 20.0% 15.0% Not Capital Nature of activities identified as being indirectly related to capital projects for this budget centre are of an administrative nature associated with activities that precede capital activity rather than a support function for departments directly involved in performing capital work

Indirect: Manager is "go-to-guy" on many matters: - litigation support, where legal costs are capitalized but internal time and costs are not - support for third-party initiatives related to capital projects (PTP-related programs) - business cases and feasibility


23 of 33





studies re: billing and metering system replacement

600 – Construction Maintenance

Direct: Budget centre capital projects (services, mains, signs, posts, markers, investigative digs, painting, piping, equipment and heavy equipment purchases) support for all large capital projects

70.0% 80.0% 75.0% Capital Overhead Management time on capital activities is considered to be incremental to capital projects

Indirect: By nature, most of groups activities relate to capital projects

700 – Technical Services

Direct: Budget center specific capital projects (capital upgrades, source and purchase materials for capital projects, SCC program costs, EVC computer and system upgrades)


Indirect: Significant amount of management time is spent on capital projects, including project studies and troubleshooting issues related to capital projects as they arise

720 – Technical Services Warehouse

Direct: No costs presently charged direct to capital projects

50.0% 50.0% 50.0% Capital Overhead Employee time related to sourcing and purchasing of capital items is considered to be incremental to capital projects

Indirect: The warehouse department is responsible for the sourcing and purchasing of all materials for capital projects

800 – Engineering and Special Projects

Direct: Costs related to design and drafting for capital projects



24 of 33





Indirect: Budget centre management's time on planning, administration and supervision, as well as time spent on actual design work related to capital projects

9X1 – Regional Operations NE

Direct: All direct costs related to construction and/or purchase of property, plant and equipment items for the region


Indirect: Management time on: annual capital plans; annual capital risk assessment; AFE review, approval and monitoring; and unexpected events requiring evaluation and subsequent capital expenditures

88 – Human Resources

Direct: No direct involvement in capital projects

0.0% 0.0% 0.0% Not Capital Nature of activities identified as being indirectly related to capital projects for this budget centre are of an administrative nature rather than a support function for departments directly involved in performing capital work

Indirect: Time and activities related to search and hiring of staff/project managers (i.e. KSL Project); time spent on HR related capital projects (Great Plains HR module)

90 – President and Chief Executive Officer

Direct: None – no direct involvement in capital projects


Indirect: Time spent on capital budgeting, cost monitoring and regulatory process


25 of 33





93/99/90 – Finance



Indirect: Time spent on capital budgeting, fixed asset accounting and rate and regulatory applications

91/92/89 – Operations & Engineering



Indirect: Management time spent on: - capital budgeting process - annual capital risk review and assessment; - capital project/capital budget oversight; - regulatory process related to capital projects

95/798 – Corporate Development, Treasury, IT



Indirect: Capital project financing; rate applications; investor relations

97 – Information Technology

Direct: No activities charged; capital purchases made


Indirect: IT-related capital projects (product assessment, supplier quotes, coordination of install)

94/96 – Regulatory Affairs


3.0% 5.0% 4.0% Capital Overhead Management time on capital activities is considered to be incremental to capital projects; activities are key to the advancement and approval of capital projects

Indirect: CPCN applications; capital-related legal matters (i.e. Porpoise Harbour); rate applications for capital projects


26 of 33

Appendix H – Evaluation of Costs for Inclusion in Overhead Capitalization

The following table summarizes costs proposed for capitalization based on this study, as well as the rationale for capitalizing these costs and the proposed allocation bases on which amounts to be capitalized are determined. Appendix I provides additional detail of the methodology to be applied.

Category Description Rationale Allocation base Field Operations (operations and administration): Support field employee labour and benefit expense

Estimated cost of staff time and associated benefit costs devoted to capital activities

Costs specific to capital support but not allocated to projects

Time spent by field operations on administration and processing of capital project transactions (AFE administration; payments processing, etc)

Apply estimated percentage of time on capital activities to identified staff labour and benefit costs

Corporate (administration): Management salary and benefit expense

Estimated cost of management time and associated benefit costs devoted to capital activities

Costs specific to capital support / oversight directly related to capital projects but not allocated to projects

A considerable amount of management time has been identified as devoted to capital projects, including time for ongoing capital planning, capital risk assessment, AFE monitoring and contingency planning

This time and the associated costs have been assessed as incremental to capital works undertaken by the Company, and therefore it is considered appropriate to capitalize a portion of these costs

Apply estimated percentage of time on capital activities to identified management salary and benefit costs

Benefits on Direct Labour: Field employee benefit expense

Estimated field employee benefit costs as determined by a benefit load analysis

Directly related to capital projects Field employee time spent on capital

projects is charged directly to capital projects

Employee benefits attributable to this time are also considered directly related to these capital projects, therefore it is appropriate to capitalize a portion of these costs

Apply standard employee benefit load rate to field labour costs capitalized to specific capital projects

Warehouse and Shop Expense

Estimated cost of staff time and associated benefit costs devoted to capital activities

Costs specific to capital support but not allocated to projects

Time spent by warehouse staff related to sourcing and purchase of materials for capital projects

Apply estimated percentage of time on capital activities to identified staff labour and benefit costs

Equipment Operating Expense

Operating costs related to transportation and heavy work equipment used in capital projects (i.e. fuel, repairs, maintenance, insurance)

Directly related to capital projects Transportation and heavy work equipment

are directly used in performance of capital activities

Operating costs can be considered directly related to the underlying activity, therefore it is appropriate to capitalize a portion of these costs

Apply standard charge out rates to hours equipment utilized for specific capital projects


27 of 33

As noted previously, the study considered all cost categories, including those historically allocated to capital projects. Some of these costs have an incremental relationship to capital projects undertaken, and it can be difficult to establish a reasonable basis on which to allocate the costs to projects. General Administrative and Overhead Costs Historically, a wide range of operating and administrative costs have been included in PNG’s overhead capitalization methodology. Many of these costs are specifically excluded from capitalization as per IAS 16:19(d), including administration and general costs. Based on this study, certain management and staff (operations accounting and warehouse) time has been identified as being dedicated to non-project specific capital support and/or oversight directly related to capital projects, and as being incremental to the Company’s capital projects. In addition, the associated employee benefit costs related to time and labour charged direct to capital projects have been proposed for capitalization. Other than these salary and employee benefit costs identified, no additional administrative, support or infrastructure costs have been identified as meeting the capitalization criteria established in Appendix F. This evaluation is based on interview feedback and difficulty in attributing specific incremental costs of this nature to capital activity. While individuals interviewed were generally able to attribute a percentage of their time as being capital-related, they were reluctant to prescribe a percentage of support/administrative costs on the basis that these costs would be incurred regardless of the level of capital activity. Warehouse and Shop Expenditures The activities of the warehouse and shop provide general support for all of the Company’s operations, including operations, maintenance and capital activities. On this basis, expenditures related to warehouse and shop activities have historically been allocated to capital. Warehouse labour costs and related employee benefits associated with time on sourcing and purchase of materials for capital projects have been identified for capitalization (see “support field employee labour and benefits” included in table above). On a cost-benefit basis, no further analysis has been undertaken to identify what additional costs related to these activities, if any, might be considered directly attributable to capital activities. Equipment Operating Expense A divergence from historic practice is that the cost of vehicle and equipment insurance (2009 – $69,000) has been incorporated into the analysis of equipment operating expenditures allocated to capital projects (see “equipment operating expense” included in table above). Unallocated Capital Amounts historically charged to this account included amounts related to capital projects but not specifically attributable to any one project. A review of costs accumulated indicates a diverse mix of items. On a go-forward basis, the day-to-day allocation of expenditures will be refined to ensure project costs are charged to specific projects and the use of this account will be discontinued.


28 of 33

Appendix I – Summary of Overhead Allocation Methodology The allocation methodology for each of the costs identified in Appendix H for inclusion in the overhead capitalization is summarized below: Capitalization of general overhead costs Field Operations (Operating and Administration): Support Field Employee Labour and Benefit Expense 1) Annual review and update of operations accounting budget centre activity to identify and

validate those involved in capital activities. 2) Obtain management estimate of percentage time devoted to capital activities for identified

budget centre. 3) Obtain field staff salary expense for budget centre as well as employee benefit load rate

compiled by Human Resources. 4) Calculate total compensation for budget centre. 5) Apply estimated percentage time devoted to capital activities to total compensation and

allocate cost to capital projects on a pro rata basis of project capital cost over total capital costs for period.

Corporate (Administration): Management Salary and Benefit Expense 1) Annual review and update of budget centre activity to identify and validate those involved in

capital activities. 2) Obtain management estimate of percentage time devoted to capital activities for identified

budget centres. 3) Obtain management salaries for budget centres as well as management employee benefit

load rate compiled by Human Resources. 4) Calculate total compensation for budget centre. 5) Apply estimated percentage time devoted to capital activities to total compensation and


Benefits on Direct Labour: Field Employee Benefit Expense 1) Identify field employee labour costs budgeted as being directly charged to capital projects. 2) Obtain field employee labour employee benefit load rate updated annually by Human

Resources. 3) Apply labour benefit load rate to labour costs charged to specific capital projects and allocate

benefit cost to capital project. Warehouse and Shop Expenditures 1) Annual review and update of operations warehouse budget centre activity to identify and

validate those involved in capital activities. 2) Obtain management estimate of percentage time devoted to capital activities for identified

budget centre. 3) Obtain field staff salary expense for budget centre as well as employee benefit load rate

compiled by Human Resources. 4) Calculate total compensation for budget centre. 5) Apply estimated percentage time devoted to capital activities to total compensation and



29 of 33

Equipment Operating Expense 1) Identify historic equipment operating costs by equipment class. 2) Obtain details of historic equipment usage, including total hours charged to projects and total

hours charged to capital projects. 3) Calculate historic operating cost per hour charged to projects and allocate to capital projects

based on total hours charged to specific capital projects. 4) True up allocation of overhead at year end based on actual costs and equipment usage. The proposed methodology developed to effect the allocation of overhead costs is considered to meet all of the evaluation criteria established in Appendix C.


30 of 33

Appendix J – Comparison of Proposed vs Current Overhead Allocation Using 2009 Figures

The following table summarizes the proposed allocation of costs based on this study compared to costs historically allocated to capital projects:

Overall2009 2009

Capitalized Overhead Element Proposed CurrentMethodology Methodology Change

1) Capitalization of general overhead costsField Operations (Operating and Administration) 415,295 754,984 (339,689) Corporate (Administration) 129,144 1,096,955 (967,811) Benefits on Direct Labour 552,507 - 552,507

1,096,946 1,851,939 (754,993)

2) Capitalization of warehouse and shop expenditures 64,287 89,650 (25,363)

3) Capitalization of equipment operating expenditures 230,283 260,754 (30,471)

4) Capitalization of unallocated capital - 90,541 (90,541)

Total Overheads Capitalized 1,391,516 2,292,884 (901,368)

Gross Operating, Maintenance, Administrative & General Costs 21,453,260 21,453,260

Percentage of Operating, Maintenance, Administrative and General Costs 6.49% 10.69% The following is a summary of items giving rise to the change in amounts proposed for capitalization from those historically capitalized: 1) Capitalization of general overhead costs – decrease of $754,993

o Historically, a diverse mix of administrative and overhead costs have been captured by the capitalization process

o Management and staff (operations accounting and warehouse) time and benefit costs considered to relate to non-project specific capital support and/or oversight directly related to capital projects, and considered incremental to the Company’s capital projects, have been proposed for capitalization

o No other administrative, support or infrastructure costs have been identified as meeting the capitalization criteria established

o Key elements of this decrease are summarized in the following table:


31 of 33

Proposed Methodology

Current Methodology

Net Increase (Decrease)

Field Operations (Operating and Administration) 100 Regional Operations - West 40,486 238,101 (197,615) 200 Customer Service - 60,133 (60,133) 300 Marketing & Lands 36,225 153 36,072 410 Operations Accounting 97,157 73,927 23,230 420 Customer Care - 34,253 (34,253) 500 Community Relations & Admin. - 15,411 (15,411) 600 Construction Maintenance 89,496 66,013 23,483 700 Technical Services 79,268 39,744 39,524 800 Engineering & Special Projects 39,634 11,569 28,065

382,266 539,304 (157,038) 931/951/961 Regional Operations – NE 33,029 427,441 (394,412)

Less: Shared Services - (211,761) 211,761 415,295 754,984 (339,689)

Corporate (Administration)90 Chief Executive Officer - 361,354 (361,354) 88 Human Resources - 395,879 (395,879)

091/092/089 Operations and Engineering 120,636 33,835 86,801 095/798 Corp. Development, Treasury, IT - 24,869 (24,869)

97 Information Technology - 90,261 (90,261) 093/099/900 Finance - 142,441 (142,441)

094/096 Regulatory 8,508 28,705 (20,197) Unallocated - 19,611 (19,611)

129,144 1,096,955 (967,811)

Benefits on Direct LabourRegional Operations - West 378,088 - 378,088 Regional Operations – NE 174,419 - 174,419

552,507 - 552,507

1,096,946 1,851,939 (754,993)

Cost Centre

No comparative amounts are presented for amounts proposed for capitalization related to benefits on direct labour. An element of these expenditures would have been captured in the historic allocation methodology by virtue of the inclusion of these expenditure amounts in the cost pools to which the approved capitalization rates were applied. However, these amounts cannot be broken out in the summary above. 2) Capitalization of warehouse and shop expenditures – decrease of $25,363

o Historically, all warehouse and shop expenditures have been capitalized; proposed methodology includes warehouse staff labour and benefit costs but excludes other costs of this budget centre

3) Capitalization of equipment operating expenditures – decrease of $30,470

o Variance arises due to fact that previous standard rates were updated annually using the greater of the historic rate and the rate based on current expenditures, as well as the inclusion of operating expenditures related to non-tracked equipment of $68,087 in the current allocation – this resulted in an higher capitalization of costs in prior years


32 of 33

o This has been partially offset by $63,000 in vehicle insurance costs being capitalized in the proposed amounts – insurance was not capitalized in the past

4) Capitalization of unallocated capital – decrease of $90,541

o Historically, full amount accumulated in “unallocated capital” account has been capitalized

o Account includes a diverse mix of costs (freight charges, bug repellant, antifreeze, cleaners for shop, office supplies, inventory count adjustments)

o Going forward, the allocation of expenditures will be refined to ensure all project costs are charged to specific projects and the use of this account will be discontinued


33 of 33

Appendix K – Revisions to Capitalization Methodology for Depreciation As part of the study of overhead capitalization, the capitalization of depreciation expense was also examined. Historically, a portion of the annual depreciation expense for certain asset classes has been allocated to the cost of capital projects at rates based on historic precedent, including the following: 484 – Transportation equipment 18% of expense capitalized 485 – Heavy work equipment 100% of expense capitalized 486 – Small tools and work equipment 48% of expense capitalized

Depreciation capitalized is allocated amongst individual capital projects based on labour hours worked on a project as a proportion of total labour hours spent on all capital projects in the year. For reference, actual depreciation expense capitalized in 2009 was $289,896. Based on a review of the underlying methodology, PNG will continue to capitalize depreciation expenditures related to equipment directly involved in capital projects, however, as a refinement to the methodology:

• the actual percentage of equipment hours used for capital work of the total equipment hours will be used as the basis for allocating these costs; and

• depreciation expense related to small tools and work equipment (2009 – $61,759) will no longer be capitalized, as from a cost-benefit perspective, the tracking and allocation of these costs to specific projects cannot be done efficiently.

The allocation methodology is substantively the same as that applied for equipment operating expenditures as per Appendix I:

Category Description Rationale Allocation base Equipment depreciation expense

Depreciation expense related to transportation and heavy work equipment used in capital projects

Directly related to capital projects Transportation and heavy work

equipment are directly used in performance of capital activities

Depreciation expense can be considered directly related to the underlying activity, therefore it is appropriate to capitalize a portion of these costs

Apply standard charge out rates to hours equipment utilized for specific capital projects

For illustrative purposes, with this refinement, depreciation expense capitalized in 2009 would have decreased by $104,894, primarily due to:

• the exclusion of small tool depreciation from costs historically capitalized ($62,000 decrease); and

• the charge-out of costs being based on actual use of heavy equipment in capital projects being 76.9% of time used compared to current allocation to capital projects equal to 100% of depreciation expense ($41,000 decrease).

Appendix B – Accounting and Regulatory Guidance

In this Appendix, we provide references to a variety of Canadian and US sources of guidance on the capitalization of overhead costs. This listing is not comprehensive, but does capture the key sources that are likely to be of interest or relevance to PNG.

A. Canadian Guidance

1. British Columbia Utilities Commission (BCUC)

While the BCUC does not publish an accounting procedures handbook with further guidance for utilities, they recognize Canadian GAAP when assessing overhead costs allocated to capital.

2. Alberta Utilities Commission (AUC) Rule 026 Rule Regarding Regulatory Account Procedures Pertaining to the Implementation of the International Financial Reporting Standards

Section 6(2) of Rule 026 provides guidance related to Specific Regulatory Accounting Items relating to Property Plant & Equipment as follows:

“(b) Capitalization/Non-Capitalization of Costs: General and Administrative Overhead (IAS 16.16 and 16.19(d))

Utilities shall adhere to the IFRS requirements for capitalization of costs that are not directly attributable to an asset. Any financial difference that arises as a result of the adoption of the IFRS requirements is to be identified in a Utility’s First IFRS-Compliant GRA/GTA, and the Utility shall also propose in that rate application the method for settling the difference. In addition, the Utility will file a copy of its updated capitalization policy as a part of its First IFRS-Compliant GRA/GTA.

(f) Capitalization/Non-Capitalization of Costs: Pre-Operating Costs (IAS 16.19, 16.20 (a) and 16.20(b))

Utilities shall adhere to the IFRS requirements regarding the treatment of pre-operating costs. Any financial difference that arises as a result of the adoption of the IFRS requirements is to be identified in a Utility’s First IFRS-Compliant GRA/GTA. The Utility shall propose in that rate application the method for settling the difference. In addition, the Utility shall file a copy of its updated capitalization policy as a part of its First IFRS-Compliant GRA/GTA.

(g) Capitalization/Non-Capitalization of Costs: Training Costs (IAS 16.19 (c))

Utilities shall adhere to the IFRS requirements regarding the capitalization of training costs. Any financial difference that arises as a result of the adoption of the IFRS requirements is to be identified in a Utility’s First IFRS-Compliant GRA/GTA. The Utility will propose in that rate application the method for settling the difference. In addition, the utility will file a copy of its updated capitalization policy as a part of its First IFRS-Compliant GRA/GTA.”

3. Ontario Energy Board’s Accounting Procedures Handbook for Electric Distribution Utilities

Article 410 of the Ontario Energy Board Accounting Procedures Handbook states:

“Property, Plant and Equipment should be recorded at cost, which includes the purchase price and other acquisition costs such as: option costs when an option is exercised, brokers’ commissions, installation costs including architectural, design and engineering fees, legal fees, survey costs, site preparation costs, freight charges, transportation insurance costs, duties, testing and preparation charges.”1

Further guidance is provided by Article 230, Definitions and Instructions, No. 20. This document defines the components of construction cost as follows:

“the cost of construction properly included in the electric plant accounts shall include where applicable, the cost of labour; materials and supplies; transportation; work done by others for the utility; injuries and damages incurred in construction work; privileges and permits; special machinery services; allowance for funds used during construction; and such portion of general engineering, administrative salaries and expenses, insurance, taxes, and other similar items as may be properly included in construction costs.”2

4. Ontario Energy Board’s Uniform System of Accounts for Class A Gas Utilities

According to the Ontario Energy Board’s Uniform System of Accounts for Class “A” Gas Utilities, Appendix A, Plant Accounting Instructions:

“Overhead Charged to Construction: includes engineering, supervision, administrative salaries and expenses, construction engineering and supervision, legal expenses, taxes and other similar items. The assignment of overhead costs to particular jobs or units shall be on the basis of a reasonable allocation of actual costs. The records supporting the entries for overhead charged to construction costs shall be maintained so as to show the total amount for each element of overhead for the year and the basis of allocation.”

5. CICA Handbook Section 3061 Property, Plant and Equipment (“PP&E”)

This Section of the Handbook of the Canadian Institute of Chartered Accountants (“CICA”) discusses measurement of PP&E. Section 3061.16 indicates that PP&E should be recorded at cost. Cost is defined in Section 3061.05 as “the amount of consideration given up to acquire, construct, develop or better an item of PP&E and includes all costs directly attributable to the acquisition, construction, development or betterment of the asset”.

When an asset is constructed or developed over time, Section 3061.20 indicates that “The cost of an item of property, plant and equipment includes direct construction or development costs (such as materials and labour), and overhead costs directly attributable to the construction or development activity.” [Emphasis ours]

The Handbook does not define the term “directly attributable”; however, this term is used throughout the handbook in various sections with reference to cost allocations. 1 Ontario Energy Board, Accounting Procedures Handbook, Article 410, p. 7. 2 Ontario Energy Board, Accounting Procedures Handbook, Article 230, p. 5.

The accounting standard does not go into further details on how the overhead costs should be identified or the actual determination of an overhead rate.

6. REALpac Accounting Practices Handbook

The Real Property Association of Canada (“REALpac”) has published a manual to provide practical and professional interpretations of accounting principles as they relate to Canadian real estate investment and development companies.

REALpac recommends that general and administrative costs directly attributable to construction of a property should be capitalized as a cost of the project. The section describes general and administrative costs to include the following:

Salaries and benefits of officers of company;

Travel and automotive costs;

Audit and legal fees;

Occupancy costs;

Stationery;

Office expenses,;

Directors’ fees;

Insurance;

Computer facility costs;

Subscriptions;

Capital and business taxes and;

Donations.

General and administrative costs that cannot be identified with a specific project or projects should not be allocated as a capitalized cost. REALpac gives the example of corporate stewardship costs as a cost that would not be capitalized.

If general and administrative costs (that qualify for capitalization) relate to a number of construction projects, then REALpac recommends that they be allocated to the projects using judgment and well supported methodology. REALpac advises that a time basis would be the most appropriate basis for allocation in most cases. The allocation method should be used on a consistent basis.

B. International Guidance

1. International Financial Reporting Standards - General

The Accounting Standards Board of Canada (“AcSB”) issued an amendment to Part I of the CICA Handbook, providing an optional one-year deferral of the mandatory date for adoption of IFRSs by entities with rate regulated activities , thereby allowing such enterprises an election to continue applying the accounting standards in Part V of the CICA Handbook for an additional year.

As a result of recent initiatives PNG expects to be required to report under International Financial Reporting Standards (“IFRS”) by 2012, but may early adopt IFRS. Therefore, at the time of this report, there is still some uncertainty regarding the details of the application of IFRS to regulated Canadian utilities.

The guidance for capitalization in IFRS is based on the standard IAS16, an extract of which is included below. IFRS is more restrictive than Canadian GAAP accounting standards for regulated utilities with respect to the capitalization of overhead costs. IFRS and Canadian standards may evolve in the period leading up to the adoption of IFRS.

2. IAS 16 Property, Plant and Equipment

The guidance under IAS 16 from the International Accounting Standards Board (IASB) prescribes the accounting treatment for property, plant and equipment so that users of the financial statements can discern information about an entity’s investment in its property, plant and equipment and the changes in such investment. The principal issues in accounting for property, plant and equipment are the recognition of the assets, the determination of their carrying amounts and the depreciation charges and impairment losses to be recognized in relation to them. Among other guidance, the standard states that:

“The cost of an item of property, plant and equipment comprises:

(a) its purchase price, including import duties and non-refundable purchase taxes, after deducting trade discounts and rebates.

(b) any costs directly attributable to bringing the asset to the location and condition necessary for it to be capable of operating in the manner intended by management.

(c) the initial estimate of the costs of dismantling and removing the item and restoring the site on which it is located, the obligation for which an entity incurs either when the item is acquired or as a consequence of having used the item during a particular period for purposes other than to produce inventories during that period.”

C. US Guidance

1. Uniform System of Accounts – Federal Energy Regulatory Commission

Under the Uniform System of Accounts prescribed for public utilities and licensees subject to provisions of the Federal Power Act, capital overhead is defined as:

“Overhead Construction Costs”

A. All overhead construction costs, such as engineering, supervision, general office salaries and expenses, construction engineering and supervision by others than the accounting utility, law expenses, insurance, injuries and damages, relief and pensions, taxes and interest, shall be charged to particular jobs or units on the basis of the amounts of such overheads reasonably applicable thereto, to the end that each job or unit shall bear its equitable proportion of such costs and that the entire cost of the unit, both direct and overhead, shall be deducted from the plant accounts at the time the property is retired.

B. As far as practicable, the determination of payroll charges included in construction overheads shall be based on time card distributions thereof. Where this procedure is impractical, special studies shall be made periodically of the time of supervisory

employees devoted to construction activities to the end that only such overhead costs as have a definite relation to construction shall be capitalized. The addition to direct construction costs of arbitrary percentages or amounts to cover assumed overhead costs is not permitted.

C. For Major utilities, the records supporting the entries for overhead construction costs shall be so kept as to show the total amount of each overhead for each year, the nature and amount of overhead expenditure charged to each construction work order and to each electric plant account, and the bases of distribution of such costs.

D. Summary

All of this guidance has a common theme. Overhead that can be directly attributed to the construction project should be capitalized as part of the cost of the project. Limited guidance is given to determine which items of overhead would be considered to be “directly attributed” to a project. It seems clear that each entity must assess its overhead expenses by type and determine if the cost is necessary to perform the construction project and if so, a portion of the cost should be capitalized. A reasonable basis of allocation must be determined. No guidance is given on allocation methods.

No single regulatory guideline, statement, or source exists that is universally accepted by utilities and regulators as the definitive statement, definition, or standard that prescribes what types of overhead costs should be considered for capitalization. However, this topic has been the subject of discussion and comment among regulators and a body of evidence exists on the topic and a number endorse a common principle: that any assignment of indirect costs to a capital project should be done based upon some reasonable causal link or association with the capital activity.

Appendix C – References

The following table details the research KPMG conducted to assess regulatory guidance and practices in other Canadian utilities.

Utility Commission Year Reference/Source Order /

Decision

TGVI BCUC 2004

Application for Approval of 2003 Actual Revenue Surplus, Forecast 2005 Royalty Adjusted Cost of Gas, Amortization of the Gas Cost Variance Account Balance and 2005 Customer Rates

G-113-04

TGI BCUC 2009 Approval of Revenue Requirements and Delivery Rates Application G-191-08

TGI BCUC 2004 Approval of 2005 Revenue Requirements and Delivery Rates G-112-04

TGI BCUC 2004 Approval of 2004 Revenue Requirements and Delivery Rates G-80-03

TGI BCUC 2009 Application for Approval of 2010 and 2011 Revenue Requirements G-141-09

TGVI BCUC 2009

Application for Approval of 2010 and 2011 Revenue Requirements, Rates, Cost of Service, Rate Design and Revenue Deficiency Deferral Account

G-140-09

BC Gas BCUC 1997 1998 to 2002 PBR Application Volume 1, Section F

BC Gas BCUC 1997 Settlement Agreement G-85-97

TGI BCUC 2003

2003 Revenue Requirement - Section 6 Accounting Issues Write up : Page E-13 Table - Section H - Tab 9, Page 2.2

TGI BCUC 2003 Section 6 - Accounting Issues Section 6.1 - Overhead Capitalized (2005) G-7-03

TGI BCUC 2003 Settlement Agreement for 2004–2007 Multi-Year Performance-Based Rate Plan Page 8, Appendix A

G-51-03

TGI BCUC 2007 Approval of 2 year extension of the Settlement (G-51-03) for 2008 and 2009 G-33-07

BCTC BCUC 2007 BCTC 2007 Revenue Requirement application with Capital Overhead Study

G-139-06 G-145-06

BCTC BCUC 2008 BCTC 2009/2010 Revenue Requirement with updated Cap Overhead methodology information

G-105-08

BCTC BCUC 2008 BCUC Negotiated Settlement to BCTC including section on Capital Overhead

BC Hydro BCUC 2008 BCH F09/10 Rev Req

BC Hydro BCUC 2006 BCH F07/08 Rev Req

BC Hydro BCUC 2009 2009/10 Revenue Requirements Decision

Utility Commission Year Reference/Source Order /

Decision

FortisBC BCUC 2009 Preliminary 2010 Revenue Requirement Application

Ottawa Hydro OEB 2007

Application by Hydro Ottawa Limited for an Order or Orders approving just and reasonable rates and other service charges for the distribution of electricity, effective May 1, 2008. Issue 3.4

EB-2007-0713

ENMAX AUC 2006 ENMAX Power Corporation 2005-2006 Distribution Tariff 2006-002

ENMAX AUC 2006 ENMAX Power Corporation 2006 TFO Tariff 2006-079

ATCO AUC 2005 ATCO Electric 2005-2007 General Tariff Application

ATCO AUC 2003 ATCO Electric 2003-2004 General Tariff Application 2003-071

PUC Distribution OEB 2007

Application by PUC Distribution Inc. for an order approving just and reasonable rates and other charges for electricity distribution to be effective May 1, 2008.

EB-2007-0931

Hydro One OEB 2005

In the matter of an application by Hydro one networks inc. For electricity distribution rates 2006 Section 4.5

RP-2005-0020 EB-2005-0378

Hydro One OEB 2007

Application by Hydro One Networks Inc. for an order or orders approving or fixing just and reasonable rates and other charges for the distribution of electricity commencing May 1, 2008.

EB-2007-0681

Hydro One OEB 2008 2009/10 Transmission Revenue Requirement and Rate Application

EB-2008-0272

Pacific Northern Gas

BCUC 2009 2009 Revenue Requirements Application G-39-09

EPCOR AUC 2004 EPCOR Distribution - 2004 DT Part B 2004 Final Distribution Tariff 2004-067

EPCOR AUC 2006 EPCOR Energy Inc. & EPCOR Energy Alberta Inc. - 2005-2006 Regulated Rate Tariff Non-Energy Charge

2006-055

AltaGas AUC 2006 AltaGas Utilities Inc. 2005/06 GRA Phase 1 2nd Compliance Filing + Errata 2006-117

AltaGas AUC 2007 AltaGas Utilities Inc. 2007 GRA Phase I 2007-094

PACIFIC NORTHERN GAS LTD. VANCOUVER, BRITISH COLUMBIA

DEPRECIATION STUDY

CALCULATED ANNUAL DEPRECIATION ACCRUAL RATES RELATED TO ORIGINAL COST OF GAS

PLANT IN SERVICE AS AT DECEMBER 31, 2009

Harrisburg, Pennsylvania Calgary, Alberta Valley Forge, Pennsylvania

GANNETT FLEMING, INC. Suite 277

200 Rivercrest Drive S.E. Calgary, Alberta T2C 2X5 Office: (403) 257-5946 Fax: (403) 257-5947 www.gannettfleming.com September 15, 2010 Pacific Northern Gas Ltd. Suite 950 – 1185 West George Street Vancouver, British Columbia V6E 4E6

Attention Ms. Janet Kennedy,

Pursuant to your request, we have conducted a depreciation study related to the original cost of investment of the natural gas transmission and distribution systems of Pacific Northern Gas Ltd as at December 31, 2009. Our report presents a description of the methods used in the estimation of depreciation and net salvage, the statistical analyses of service life, and the summary and detailed tabulations of annual and accrued depreciation.

The calculated annual depreciation accrual rates presented in the report are based on the straight-line whole life method using the average service life group procedure, applied on a remaining life basis. An annual review of the depreciation rates using the same estimates and methods is recommended.

Respectfully submitted,

GANNETT FLEMING, INC.

LARRY E. KENNEDY Director, Canadian Operations LEK:hac Project:051669

TABLE OF CONTENTS

PART I. INTRODUCTION

Scope ...................................................................................................................... I-2 Basis of the Study ................................................................................................... I-3

Depreciation ................................................................................................. I-3 Service Life Estimates .................................................................................. I-3

Recommendations .................................................................................................. I-4

PART II. METHODS USED IN THE ESTIMATION OF DEPRECIATION Depreciation ............................................................................................................ II-2 Estimation of Survivor Curves ................................................................................. II-3 Survivor Curves ............................................................................................ II-3 Iowa Type Curves ......................................................................................... II-4 Retirement Rate Method of Analysis ............................................................ II-6 Schedules of Annual Transactions in Plant Records .................................... II-11 Schedule of Plant Exposed to Retirement .................................................... II-14 Original Life Table ........................................................................................ II-15 Smoothing Original Survivor Curve .............................................................. II-17 Computed Mortality Method.......................................................................... II-23 Simulated Plant Balance Method .................................................................. II-24 Survivor Curve Judgments ........................................................................... II-24 Calculation of Annual and Accrued Depreciation .................................................... II-26

Group Depreciation Procedures ................................................................... II-26

PART III. RESULTS OF STUDY Qualifications of Results .......................................................................................... III-2 Description of Detailed Tabulations ......................................................................... III-2 Schedule 1A West System - Estimated Survivor Curve, Original Cost, Book Depreciation Reserve and Calculated Annual Depreciation Accruals Related to Utility Plant At December 31, 2009 ........................................................................................................ III-4 Schedule 1B Dawson Creek - Estimated Survivor Curve, Original Cost, Book Depreciation Reserve and Calculated Annual Depreciation Accruals Related to Utility Plant At December 31, 2009

........................................................................................................ III-5

iii

TABLE OF CONTENTS, cont. Schedule 1C Fort St. John - Estimated Survivor Curve, Original Cost, Book Depreciation Reserve and Calculated Annual Depreciation Accruals Related to Utility Plant At December 31, 2009 ................ III-6 Schedule 1D Tumbler Ridge - Estimated Survivor Curve, Original Cost, Book Depreciation Reserve and Calculated Annual Depreciation Accruals Related to Utility Plant At December 31, 2009 ................ III-7 Schedule 2 Summary of Peer Average Service Life Estimates .......................... III-8

PART IV. SERVICE LIFE STATISTICS Service Life Statistics .............................................................................................. IV-2

PART V. DETAILED DEPRECIATION CALCULATIONS

Detailed Depreciation Calculations ......................................................................... V-1 West System ........................................................................................... V-2 Dawson Creek ......................................................................................... V-29 Fort St. John ............................................................................................ V-49 Tumbler Ridge ......................................................................................... V-71

iv


PACIFIC NORTHERN GAS LIMITED. DEPRECIATION STUDY

CALCULATED ANNUAL DEPRECIATION ACCRUAL RATES RELATED TO THE ORIGINAL COST OF GAS PLANT IN SERVICE AS AT

DECEMBER 31, 2009


SCOPE

This report sets forth the results of the depreciation study conducted for the

natural gas transmission and distribution assets of Pacific Northern Gas Ltd. (“PNG” or

“the Company”) to determine the annual depreciation accrual rates and amounts

applicable to the original cost of gas plant as at December 31, 2009.

The depreciation accrual rates presented herein are based on generally-

accepted methods and procedures for calculating depreciation. The estimated survivor

curves and estimated net salvage percents used in this report are based on studies

incorporating data through 2009 for most accounts.

The Canadian Accounting Standards Board has announced that Canadian

generally accepted Accounting Principles (GAAP) will be adapted to comply for

reporting purposes with the International Financial Reporting Standards (IFRS) by

2011.1 In preparation for the implementation of the new standard, this depreciation

study has included a review of the appropriateness of the current level of

componentization to meet the requirements of the IFRS.

Part I, Introduction, contains statements with respect to the scope of the report

and the basis of the study. Part II, Methods Used in the Estimation of Depreciation,

1 However, the CICA has recently announced a potential I year exemption for rate regulated entities in the implementation of the IFRS.

I-2

presents the methods used in the estimation of average service lives, and survivor

curves in the calculation of depreciation. Part III, Results of Study, presents a summary

of annual depreciation, the statistical analyses of service lives, and the detailed

tabulations of annual depreciation.

BASIS OF THE STUDY Depreciation. The annual depreciation accrual and the related calculated

requirements for accumulated depreciation were calculated using the straight line

method, the remaining life basis and the average service life (ASL) procedure. The

calculation was based on the attained ages and estimated service life and net salvage

characteristics for each depreciable group of assets as at December 31, 2009.

Service Life Estimates. The method of estimating service life consisted of

compiling the service life history of the plant accounts and subaccounts, reducing this

history to trends through the use of analytical techniques that have been generally

accepted in various regulatory jurisdictions, and forecasting the trend of survivors for

each depreciable group on the basis of interpretations of past trends and consideration

of Company plans for the future. The combination of the historical trend and the

estimated future trend yielded a complete pattern of life characteristics from which the

average service life was derived. The service life estimates used in the depreciation

calculation incorporated historical data compiled through December 31, 2009. Such

data included plant additions, retirements, transfers and other plant activity.

Gannett Fleming conducted a field tour of the PNG right of way and company

facilities in order to gain an understanding of the terrain of the pipeline right of way and

general condition and of the plant. Additionally, Gannett Fleming conducted

I-3

management and operational meetings to review the current policies and operational

practices of the company.

RECOMMENDATIONS

The annual and accrued depreciation were calculated by the straight line

using the average service life (“ASL”) procedure. The calculations were based on the

cost and attained ages as of December 31, 2009. The ASL procedure was previously

used for PNG’s last depreciation study, dated September 1995, and has continued to be

used for the purposes of this study. Although, in the opinion of Gannett Fleming, the

equal life group (“ELG”) procedure is superior to the ASL procedure in matching

depreciation expense and consumption of service value, the average service life

procedure is appropriate and conforms to past practices.

The calculated annual depreciation accrual rates set forth herein apply

specifically to plant in service as at December 31, 2009. Continued surveillance and

periodic revisions are normally required to maintain continued use of appropriate

depreciation rates.

The depreciation rates should be reviewed annually to reflect the changes that

result from plant and reserve account activity. A depreciation reserve deficiency or

surplus will develop if future capital expenditures vary significantly from those

anticipated in this study. The survivor curves and amortization periods used in this

study should be the basis for annual recalculations. Complete depreciation studies,

which reevaluate these parameters, should be performed every three to five years.

I-4

PART II. METHODS USED IN THE

ESTIMATION OF DEPRECIATION

PART II. METHODS USED IN THE ESTIMATION OF DEPRECIATION DEPRECIATION

Depreciation, in public utility regulation, is the loss in service value not restored

by current maintenance, incurred in connection with the consumption or prospective

retirement of utility plant in the course of service from causes which are known to be in

current operation and against which the utility is not protected by insurance. Among

causes to be given consideration are wear and tear, deterioration, action of the

elements, inadequacy, obsolescence, changes in the art, changes in demand, and the

requirements of public authorities.

Depreciation, as used in accounting, is a method of distributing fixed capital

costs, less net salvage, over a period of time by allocating annual amounts to expense.

Each annual amount of such depreciation expense is part of that year's total cost of

providing natural gas distribution service. Normally, the period of time over which the

fixed capital cost is allocated to the cost of service is equal to the period of time over

which an item renders service, that is, the item's service life. The most prevalent

method of allocation is to distribute an equal amount of cost to each year of service life.

This method is known as the straight-line method of depreciation.

The calculation of annual and accrued depreciation based on the straight line

method requires the estimation of survivor curves and the selection of group

depreciation procedures. These subjects are discussed in the sections that follow.

II-2

ESTIMATION OF SURVIVOR CURVES Survivor Curves. The use of an average service life for a property group implies

that the various units in the group have different lives. Thus, the average life may be

obtained by determining the separate lives of each of the units, or by constructing a

survivor curve by plotting the number of units which survive at successive ages. A

discussion of the general concept of survivor curves is presented. Also, the Iowa type

survivor curves are reviewed.

The survivor curve graphically depicts the amount of property existing at each

age throughout the life of an original group. From the survivor curve, the average life of

the group, the remaining life expectancy, the probable life, and the frequency curve can

be calculated. In Figure 1, a typical smooth survivor curve and the derived curves are

illustrated. The average life is obtained by calculating the area under the survivor curve,

from age zero to the maximum age, and dividing this area by the ordinate at age zero.

The remaining life expectancy at any age can be calculated by obtaining the area under

the curve, from the observation age to the maximum age, and dividing this area by the

percent surviving at the observation age. For example, in Figure 1, the remaining life at

age 30 is equal to the crosshatched area under the survivor curve divided by 29.5

percent surviving at age 30. The probable life at any age is developed by adding the

age and remaining life. If the probable life of the property is calculated for each year of

age, the probable life curve shown in the chart can be developed. The frequency curve

presents the number of units retired in each age interval and is derived by obtaining the

differences between the amount of property surviving at the beginning and at the end of

each interval.

II-3

Iowa Type Curves The range of survivor characteristics usually experienced by

utility and industrial properties is encompassed by a system of generalized survivor

curves known as the Iowa type curves. There are four families in the Iowa system,

labeled in accordance with the location of the modes of the retirements in relationship to

the average life and the relative height of the modes. The left moded curves, presented

in Figure 2, are those in which the greatest frequency of retirement occurs to the left of,

or prior to, average service life. The symmetrical moded curves, presented in Figure 3,

are those in which the greatest frequency of retirement occurs at average service life.

The right moded curves, presented in Figure 4, are those in which the greatest

frequency occurs to the right of, or after, average service life. The origin moded curves,

presented in Figure 5, are those in which the greatest frequency of retirement occurs at

the origin, or immediately after age zero. The letter designation of each family of curves

(L, S, R or O) represents the location of the mode of the associated frequency curve

with respect to the average service life. The numbers represent the relative heights of

the modes of the frequency curves within each family.

The Iowa curves were developed at the Iowa State College Engineering

Experiment Station through an extensive process of observation and classification of

the ages at which industrial property had been retired. A report of the study which

resulted in the classification of property survivor characteristics into 18 type curves,

which constitute three of the four families, was published in 1935 in the form of the

Experiment Station’s Bulletin 125.2 These type curves have also been presented in

2 Winfrey, Robley. Statistical Analyses of Industrial Property Retirements. Iowa State College, Engineering Experiment Station, Bulletin 125. 1935. II-4

II-5

subsequent Experiment Station bulletins and in the text, "Engineering Valuation and

Depreciation."3 In 1957, Frank V. B. Couch, Jr., an Iowa State College graduate

student, submitted a thesis4 presenting his development of the fourth family consisting

of the four O type survivor curves.

Retirement Rate Method of Analysis. The retirement rate method is an actuarial

method of deriving survivor curves using the average rates at which property of each

age group is retired. The method relates to property groups for which aged accounting

experience is available or for which aged accounting experience is developed by

statistically aging un-aged amounts and is the method used to develop the original stub

survivor curves in this study. The method (also known as the annual rate method) is

illustrated through the use of an example in the following text, and is also explained in

several publications, including "Statistical Analyses of Industrial Property Retirements,"5

"Engineering Valuation and Depreciation,"6 and "Depreciation Systems."7

The average rate of retirement used in the calculation of the percent surviving for

the survivor curve (life table) requires two sets of data: first, the property retired during

a period of observation, identified by the property's age at retirement; and second,

the property exposed to retirement at the beginnings of the age intervals during the

same period. The period of observation is referred to as the experience band, and the

band of years which represent the installation dates of the property exposed to

3Marston, Anson, Robley Winfrey and Jean C. Hempstead. Engineering Valuation and Depreciation, 2nd Edition. New York, McGraw-Hill Book Company. 1953.

4Couch, Frank V. B., Jr. "Classification of Type O Retirement Characteristics of Industrial Property." Unpublished M.S. thesis (Engineering Valuation). Library, Iowa State College, Ames, Iowa. 1957. 5Winfrey, Robley, Supra Note 1. 6Marston, Anson, Robley Winfrey, and Jean C. Hempstead, Supra Note 2. 7Wolf, Frank K. and W. Chester Fitch. Depreciation Systems. Iowa State University Press. 1994

II-6

II-7

II-8

II-9

II-10

retirement during the experience band is referred to as the placement band. An

example of the calculations used in the development of a life table follows. The

example includes schedules of annual aged property transactions, a schedule of plant

exposed to retirement, a life table and illustrations of smoothing the stub survivor curve.

Schedules of Annual Transactions in Plant Records. The property group used to

illustrate the retirement rate method is observed for the experience band 2000-2009

during which there were placements during the years 1995-2009. In order to illustrate

the summation of the aged data by age interval, the data were compiled in the manner

presented in Tables 1 and 2 on the following pages. In Table 1, the year of installation

(year placed) and the year of retirement are shown. The age interval during which a

retirement occurred is determined from this information. In the example which follows,

$10,000 of the dollars invested in 1995 were retired in 2000. The $10,000 retirement

occurred during the age interval between 4½ and 5½ years on the basis that

approximately one-half of the amount of property was installed prior to and subsequent

to July 1 of each year. That is, on the average, property installed during a year is

placed in service at the midpoint of the year for the purpose of the analysis. All

retirements also are stated as occurring at the midpoint of a one-year age interval of

time, except the first age interval which encompasses only one-half year.

The total retirements occurring in each age interval in a band are determined by

summing the amounts for each transaction year-installation year combination for that

age interval. For example, the total of $143,000 retired for age interval 4½-5½ is the

sum of the retirements entered on Table 1 immediately above the stairstep line drawn

on the table beginning with the 2000 retirements of 1995 installations and ending

II-11

TAB

LE 1

. R

ETIR

EM

ENTS

FO

R E

AC

H Y

EAR

200

0-20

09

SU

MM

AR

IZE

D B

Y A

GE

INTE

RV

AL

Exp

erie

nce

Ban

d 20

00-2

009

P

lace

men

t Ban

d 19

95-2

009

Ret

irem

ents

, Tho

usan

ds o

f Dol

lars

Ye

ar

Pla

ced

D

urin

g Ye

ar

To

tal D

urin

g A

ge In

terv

al

Age

Inte

rval

20

00

2001

20

02

2003

20

04

2005

20

06

2007

20

08

2009

(1

) (2

) (3

) (4

) (5

) (6

) (7

) (8

) (9

) (1

0)

(11)

(1

2)

(13)

1995

10

11

12

13

14

16

23

24

25

26

26

1

3½-1

4½

1996

11

12

13

15

16

18

20

21

22

19

44

1

2½-1

3½

1997

11

12

13

14

16

17

19

21

22

18

64

1

1½-1

2½

1998

8

9

10

11

11

13

14

15

16

17

83

1

0½-1

1½

1999

9

10

11

12

13

14

16

17

19

20

93

9½

-10½

20

00

4

9

10

11

12

13

14

15

16

20

10

5

8½-9

½

20

01

5

11

12

13

14

15

16

18

20

113

7½

-8½

2002

6

12

13

15

16

17

19

19

124

6½

-7½

2003

6

13

15

16

17

19

19

13

1

5½-6

½

20

04

7 14

16

17

19

20

14

3

4½-5

½

20

05

8

18

20

22

23

146

3½

-4½

2006

9

20

22

25

150

2½

-3½

2007

11

23

25

15

1

1½-2

½

20

08

11

24

153

½

-1½

2009

13

8

0

0-½

To

tal

53

68

86

106

12

8

157

19

6

231

27

3

308

1,

606

II-12

TA

BLE

2.

OTH

ER

TR

AN

SA

CTI

ON

S F

OR

EA

CH

YE

AR

200

0-20

09

SU

MM

AR

IZE

D B

Y A

GE

INTE

RV

AL

E

xper

ienc

e B

and

2000

-200

9

Pla

cem

ent B

and

1995

-200

9

Acq

uisi

tions

, Tra

nsfe

rs a

nd S

ales

, Tho

usan

ds o

f Dol

lars

D

urin

g Ye

ar__

____

____

____

____

____

____

__

To

tal D

urin

g A

ge

Pla

ced

(1)

2000

(2

)

2001

(3

)

2002

(4

)

2003

(5

)

2004

(6

)

2005

(7

)

2006

(8

)

2007

(9

)

2008

(1

0)

2009

(1

1)

Age

Inte

rval

(1

2)

Inte

rval

(1

3)

19

95

- -

- -

- -

60a

- -

- -

13½

-14½

19

96

- -

- -

- -

- -

- -

- 12

½-1

3½

1997

-

- -

- -

- -

- -

- -

11½

-12½

19

98

- -

- -

- -

- (5

)b -

- 60

10

½-1

1½

1999

-

- -

- -

- -

6 a

- -

- 9

½-1

0½

2000

- -

- -

- -

- -

- (5

) 8

½-9

½

2001

-

- -

- -

- -

- -

7½-8

½

2002

-

- -

- -

- -

- -

6½

-7½

20

03

-

- -

- (1

2)b

- -

- 5

½-6

½

2004

-

- -

- 22

a -

- 4

½-5

½

2005

- -

(19)

b -

- 10

3

½-4

½

2006

-

- -

- -

2½

-3½

20

07

-

- (1

02)c

(121

) 1

½-2

½

2008

-

-

-

½-1

½

2009

-

0-½

Tota

l -

-

-

-

-

-

60

(3

0)

22

(1

02)

( 50)

a T

rans

fer A

ffect

ing

Exp

osur

es a

t Beg

inni

ng o

f Yea

r

b Tra

nsfe

r Affe

ctin

g E

xpos

ures

at E

nd o

f Yea

r

c Sal

e w

ith C

ontin

ued

Use

Par

enth

eses

den

ote

Cre

dit a

mou

nt.

II-13

with the 2009 retirements of the 2004 installations. Thus, the total amount of 143 for

age interval 4½-5½ equals the sum of:

10 + 12 + 13 + 11 + 13 + 13 + 15 + 17 + 19 + 20.

In Table 2, other transactions which affect the group are recorded in a similar

manner. The entries illustrated include transfers and sales. The entries which are

credits to the plant account are shown in parentheses. The items recorded on this

schedule are not totaled with the retirements, but are used in developing the exposures

at the beginning of each age interval.

Schedule of Plant Exposed to Retirement. The development of the amount of

plant exposed to retirement at the beginning of each age interval is illustrated in Table 3

on page ll-16. The surviving plant at the beginning of each year from 2000 through

2009 is recorded by year in the portion of the table headed "Annual Survivors at the

Beginning of the Year." The last amount entered in each column is the amount of new

plant added to the group during the year. The amounts entered in Table 3 for each

successive year following the beginning balance or addition, are obtained by adding or

subtracting the net entries shown on Tables 1 and 2. For the purpose of determining

the plant exposed to retirement, transfers-in are considered as being exposed to

retirement in this group at the beginning of the year in which they occurred, and the

sales and transfers-out are considered to be removed from the plant exposed to

retirement at the beginning of the following year. Thus, the amounts of plant shown

at the beginning of each year are the amounts of plant from each placement year

considered to be exposed to retirement at the beginning of each successive transaction

year. For example, the exposures for the installation year 2005 are calculated in the

following manner:

II-14

Exposures at age 0 = amount of addition = $750,000 Exposures at age ½ = $750,000 - $ 8,000 = $742,000 Exposures at age 1½ = $742,000 - $18,000 = $724,000 Exposures at age 2½ = $724,000 - $20,000 - $19,000 = $685,000 Exposures at age 3½ = $685,000 - $22,000 = $663,000 For the entire experience band 2000-2009, the total exposures at the beginning

of an age interval are obtained by summing diagonally in a manner similar to the

summing of the retirements during an age interval (Table 1). For example, the figure of

3,789, shown as the total exposures at the beginning of age interval 4½-5½, is obtained

by summing:

255 + 268 + 284 + 311 + 334 + 374 + 405 + 448 + 501 + 609.

Original Life Table. The original life table, illustrated in Table 4 on page ll-18, is

developed from the totals shown on the schedules of retirements and exposures,

Tables 1 and 3, respectively. The exposures at the beginning of the age interval are

obtained from the corresponding age interval of the exposure schedule, and the

retirements during the age interval are obtained from the corresponding age interval of

the retirement schedule. The retirement ratio is the result of dividing the retirements

during the age interval by the exposures at the beginning of the age interval. The

percent surviving at the beginning of each age interval is derived from survivor ratios,

each of which equals one minus the retirement ratio. The percent surviving is

developed by starting with 100% at age zero and successively multiplying the percent

surviving at the beginning of each interval by the survivor ratio, i.e., one minus the

retirement ratio for that age interval. The calculations necessary to determine the

percent surviving at age 5½ are as follows:

II-15

TAB

LE 3

. P

LAN

T E

XPO

SE

D T

O R

ETIR

EM

EN

T JA

NU

AR

Y 1

OF

EA

CH

YE

AR

200

0-20

09

SU

MM

AR

IZE

D B

Y A

GE

INTE

RV

AL

Exp

erie

nce

Ban

d 20

00-2

009

P

lace

men

t Ban

d 19

95-2

009

a Add

ition

s du

ring

the

year

.

Year

Exp

osur

es, T

hous

ands

of D

olla

rs

Ann

ual S

urvi

vors

at t

he B

egin

ning

of t

he Y

ear

Tot

al a

t B

egin

ning

of A

ge

A

ge

Pla

ced

(1)

200

0

(2)

200

1

(3)

200

2

(4)

200

3

(5)

200

4

(6)

200

5

(7)

200

6

(8)

200

7

(9)

200

8 (

10)

200

9 (

11)

In

terv

al

(1

2)

Inte

rval

(

13)

1995

2

55

245

2

34

222

2

09

195

2

39

216

1

92

167

167

13½

-14½

19

96

279

2

68

256

2

43

228

2

12

194

1

74

153

1

31

3

23

12½

-13½

19

97

307

2

96

284

2

71

257

2

41

224

2

05

184

1

62

5

31

11½

-12½

19

98

338

3

30

321

3

11

300

2

89

276

2

62

242

2

26

8

23

10½

-11½

19

99

376

3

67

357

3

46

334

3

21

307

2

97

280

2

61

1,0

97

9½

-10½

20

00

420

a 4

16

407

3

97

386

3

74

361

3

47

332

3

16

1,5

03

8½

-9½

20

01

4

60a

455

4

44

432

4

19

405

3

90

374

3

56

1,9

52

7½

-8½

20

02

510

a 5

04

492

4

79

464

4

48

431

4

12

2,4

63

6½

-7½

20

03

5

80a

574

5

61

546

5

30

501

4

82

3,0

57

5½

-6½

20

04

660

a 6

53

639

6

23

628

6

09

3,7

89

4½

-5½

20

05

7

50a

742

7

24

685

6

63

4,3

32

3½

-4½

20

06

850

a 8

41

821

7

99

4,9

55

2½

-3½

20

07

9

60a

949

9

26

5,7

19

1½

-2½

20

08

1,08

0a 1,

069

6,5

79

½

-1½

20

09

___

___

___

____

_

___

_

___

_

____

_

_

___

___

7

,490

0-½

To

tal

1,97

5

2,38

2

2,82

4

3,31

8

3,87

2

4,49

4

5,24

7

6,01

7

6,85

2

7,79

9

44,

780

II-16

Percent surviving at age 4½ = 88.15 Exposures at age 4½ = 3,789,000 Retirements from age 4½ to 5½ = 143,000 Retirement Ratio = 143,000 ÷ 3,789,000 = 0.0377 Survivor Ratio = 1.000 - 0.0377 = 0.9623 Percent surviving at age 5½ = (88.15) x (0.9623) = 84.83

The totals of the exposures and retirements (columns 2 and 3) are shown for the

purpose of checking with the respective totals in Tables 1 and 3. The ratio of the total

retirements to the total exposures, other than for each age interval, is meaningless.

The original survivor curve is plotted from the original life table (column 6, Table

4). When the curve terminates at a percent surviving greater than zero, it is called a

stub survivor curve. Survivor curves developed from retirement rate studies generally

are stub curves.

Smoothing the Original Survivor Curve. The smoothing of the original survivor

curve eliminates any irregularities and serves as the basis for the preliminary

extrapolation to zero percent surviving of the original stub curve. Even if the original

survivor curve is complete from 100% to zero percent, it is desirable to eliminate any

irregularities, as there is still an extrapolation for the vintages which have not yet lived to

the age at which the curve reaches zero percent. In this study, the smoothing of the

original curve with established type curves was used to eliminate irregularities in the

original curve.

The Iowa type curves are used in this study to smooth those original stub curves

which are expressed as percents surviving at ages in years. Each original survivor

curve was compared to the Iowa curves using visual and mathematical matching in

II-17

TABLE 4. ORIGINAL LIFE TABLE CALCULATED BY THE RETIREMENT RATE METHOD

Experience Band 2000-2009 Placement Band 1995-2009

(Exposure and Retirement Amounts are in Thousands of Dollars)

Age at

Beginning of Interval

(1)

Exposures at Beginning of Age Interval

(2)

Retirements During Age

Interval (3)

Retirement Ratio

(4)

Survivor Ratio

(5)

Percent Surviving at Beginning of Age Interval

(6)

0.0 7,490 80 0.0107 0.9893 100.00 0.5 6,579 153 0.0233 0.9767 98.93 1.5 5,719 151 0.0264 0.9736 96.62 2.5 4,955 150 0.0303 0.9697 94.07 3.5 4,332 146 0.0337 0.9663 91.22 4.5 3,789 143 0.0377 0.9623 88.15 5.5 3,057 131 0.0429 0.9571 84.83 6.5 2,463 124 0.0503 0.9497 81.19 7.5 1,952 113 0.0579 0.9421 77.11 8.5 1,503 105 0.0699 0.9301 72.65 9.5 1,097 93 0.0848 0.9152 67.57 10.5 823 83 0.1009 0.8991 61.84 11.5 531 64 0.1205 0.8795 55.60 12.5 323 44 0.1362 0.8638 48.90 13.5 167 26 0.1557 0.8443 42.24

35.66

Total

44,780

1,606

Column 2 from Table 3, Column 12, Plant Exposed to Retirement. Column 3 from Table 1, Column 12, Retirements for Each Year. Column 4 = Column 3 divided by Column 2. Column 5 = 1.0000 minus Column 4. Column 6 = Column 5 multiplied by Column 6 as of the Preceding Age Interval.

II-18

II-19

II-20

II-21

II-22

order to determine the better fitting smooth curves. In Figures 6, 7, and 8, the original

curve developed in Table 4 is compared with the L, S, and R Iowa type curves which

most nearly fit the original survivor curve. In Figure 6, the L1 curve with an average life

between 12 and 13 years appears to be the best fit. In Figure 7, the S0 type curve with

a 12-year average life appears to be the best fit and appears to be better than the L1

fitting. In Figure 8, the R1 type curve with a 12-year average life appears to be the best

fit and appears to be better than either the L1 or the S0.

In Figure 9, the three fittings, 12-L1, 12-S0 and 12-R1 are drawn for comparison

purposes. It is probable that the 12-R1 Iowa curve would be selected as the most

representative of the plotted survivor characteristics of the group.

Computed Mortality Method. The computed mortality method of life analysis as

used in this study is a procedure for statistically aging annual retirements prior to being

analyzed by the retirement rate method. In this procedure, an aged plant balance is

developed for the year prior to and for each test year during the given term of

comparison. Each given balance is aged by a simulation procedure which applies a

series of successive survivor curve trials using a specified Iowa type curve. The Iowa

type survivor curve specified for each account is based on judgment incorporating the

results of simulated plant record analyses, knowledge of the property and the type

curves estimated for the account in other electric companies. Each trial consists of

constructing a specific survivor curve at one-year intervals beginning with age 1/2.

From this curve, survivor ratios are computed and applied, by vintage, to the previous

year's aged ending balance and the current test year's given gross addition. The

resultant aged surviving balances also produce the aged retirements which are the

II-23

differences between successive aged balances. The aged data are then analyzed by

the retirement rate method as described above.

Simulated Plant Balance Method. The simulated plant balance method of life

analysis is a statistical procedure by which experienced average service life and

survivor characteristics are inferred through a series of approximations in which several

average service life and survivor curve combinations are tested. The testing procedure

consists of applying survivor ratios defined by the average service life and survivor

curve combinations being tested to historical plant additions and comparing the

resulting calculated, or simulated, surviving balances with the actual surviving balances.

Each year-end book balance is the sum of the plant surviving from the original

annual additions. Each calculated year-end balance is the sum of the simulated plant

surviving from the same original annual additions. The simulated survivors are

calculated for each vintage by multiplying the original additions by the percent surviving

corresponding to the age of the vintage as of the date of the year-end balances being

simulated. This procedure is repeated until a series of simulated balances are

calculated. The balances are then compared with the book balances to determine

which average service life and survivor curve combinations result in calculated balances

most nearly simulating the progression of actual balances.

The simulated plant record method is presented in greater detail in the Edison

Electric Institute’s publication, “Methods of Estimating Utility Plant Life.”8

Survivor Curve Judgments. The survivor curve estimates were based on

judgment which considered a number of factors. The primary factors were the statistical 8 A Report of the Engineering Subcommittee of the Depreciation Accounting Committee, Edison Electric Institute. Publication No. 51-23. Published 1952.

II-24

analysis of data; current policies and outlook as determined through conversations with

operations and management personnel over a number of years; and survivor curve

estimates from previous studies of this company and other natural gas distribution and

transmission companies.

The Transmission and Distribution assets of PNG have experienced only limited

retirement activity. The results of the retirement rate analysis as presented in this report

starting at page IV-2 indicate stubbed survivor curves for most accounts. In these

circumstances the development of average service life estimates predominantly

weighted on the results of the retirement rate study results is not reasonable. As such,

Gannett Fleming reviewed the approved average service life estimates for a group of

peer natural gas transmission and distribution utilities. The selection of the peer group

was based on the following factors:

Regulatory jurisdiction

Size and asset base

Geographic diversity

Given the above factors, Gannett Fleming viewed the following natural gas utilities to

provide a reasonable comparison base for use in the selection of Average Service Life

estimates:

Terasen Gas Inc.

AltaGas Utilities Inc.

Manitoba Hydro (Centra Gas Manitoba)

ATCO Gas

Gazifere

II-25

The results of the peer analysis are presented in Schedule 2 of the Results

section of this report.

The final survivor curve estimates were developed following a discussion with the

PNG operating staff which reviewed the results of the retirement rate analysis, the

results of the peer comparison, and the company operating, capitalization and

retirement policies.

CALCULATION OF ANNUAL AND ACCRUED DEPRECIATION

Group Depreciation Procedures. When more than a single item of property is

under consideration, a group procedure for depreciation is appropriate because

normally all of the items within a group do not have identical service lives, but have lives

that are dispersed over a range of time. There are two primary group procedures,

namely, average service life and equal life group.

In the average service life procedure, the rate of annual depreciation is based on

the average life or average service life of the group, and this rate is applied to the

surviving balances of the group's cost. A characteristic of this procedure is that the cost

of plant retired prior to average life is not fully recouped at the time of retirement,

whereas the cost of plant retired subsequent to average life is more than fully recouped.

Over the entire life cycle, the portion of cost not recouped prior to average life is

balanced by the cost recouped subsequent to average life. In this procedure, the

accrued depreciation is based on the average service life of the group and the average

remaining life of each vintage within the group derived from the area under the survivor

curve between the attained age of the vintage and the maximum age.

II-26

In the equal life group procedure, the property group is subdivided according to

service life. That is, each equal life group includes that portion of the property which

experiences the life of that specific group. The relative size of each equal life group is

determined from the property's life dispersion curve. The calculated depreciation for the

property group is the summation of the calculated depreciation based on the service life

of each equal life group.

It is the view of Gannett Fleming that the ELG procedure provides a superior

match of the consumption of service values of the assets in service to the depreciation

expense. However, the ASL procedure is widely used throughout North America and

has been used historically by both PNG and Terasen Gas in the province of British

Columbia. Additionally, Gannett Fleming understands that the ASL procedure is

acceptable for the determination of the annual depreciation accrual for IFRS purposes.

As such Gannett Fleming has incorporated the use of the ASL procedure in the

calculation of the depreciation accrual rates in this depreciation study.

II-27

PART III. RESULTS OF STUDY

PART III. RESULTS OF STUDY

QUALIFICATION OF RESULTS

The calculated annual and accrued depreciation and the calculation of the

composite average remaining life are the principal results of the study. Continued

surveillance and periodic revisions are normally required to maintain continued use of

appropriate annual depreciation accrual rates. An assumption that accrual rates can

remain unchanged over a long period of time implies a disregard for the inherent

variability in service lives and salvage and for the change of the composition of property

in service. The annual accrual rates and the accrued depreciation were calculated in

accordance with the straight line method, using the average service life procedure

based on estimates which reflect considerations of current historical evidence and

expected future conditions.

DESCRIPTION OF DETAILED TABULATIONS

The service life and net salvage estimates were based on judgment that

incorporated statistical analysis of retirement data, discussions with management and

consideration of estimates made for other natural gas utilities. The results of the

statistical analysis of service life are presented in the section beginning on pages IV-2.

For each depreciable group analyzed by the retirement rate method, a chart

depicting the original and estimated survivor curves followed by a tabular presentation

of the original life table(s) plotted on the chart. The survivor curves estimated for the

depreciable groups are shown as dark smooth curves on the charts. Each smooth

survivor curve is denoted by a numeral followed by the curve type designation. The

III-2

numeral used is the average life derived from the entire curve from 100 percent to zero

percent surviving. The titles of the chart indicate the group, the symbol used to plot the

points of the original life table, and the experience and placement bands of the life

tables which where plotted. The experience band indicates the range of years for which

retirements were used to develop the stub survivor curve. The placements indicate, for

the related experience band, the range of years of installations which appear in the

experience.

The tables of the calculated annual depreciation applicable to the plant in service

as at December 31, 2009 are presented in account sequence starting at page V-2. The

tables indicate the estimated average survivor curves and net salvage percents used in

the calculations. The tables set forth, for each installation year, the original cost,

calculated accrued depreciation, and the calculated annual accrual.

III-3

OR

IGIN

AL C

OST

BO

OK

CO

MPO

SITE

SUR

VIVO

RN

ETAT

DEP

REC

IATI

ON

FUTU

RE

ACC

RU

ALAC

CR

UAL

R

EMAI

NIN

G

DEP

REC

IAB

LE W

OR

KC

UR

VESA

LVAG

ED

ECEM

BER

31,

200

9R

ESER

VEAC

CR

UAL

SAM

OU

NT

RAT

ELI

FE(1

)(2

)(3

)(4

)(5

)(6

)(7

)(8

)=(7

)/(4)

(9)=

(6)/(

7)

PRO

CES

SIN

G P

LAN

T44

3.00

GAS

HO

LDER

S - S

TOR

AGE

40-S

Q0

30,0

00.0

0

7,

800

22

,200

80

72.

69

27

.544

9.00

OTH

ER L

OC

AL S

TOR

AGE

EQU

IPM

ENT

33-R

30

3,20

0.00

1,

585

1,

615

762.

38

21

.3

TOTA

L PR

OC

ESSI

NG

PLA

NT

33,2

00.0

0

9,

385

23

,815

88

3

TRAN

SMIS

SIO

N P

LAN

T46

1.00

LAN

D R

IGH

TS75

-R4

01,

170,

732.

11

-

1,17

0,73

2

32

,338

2.76

36.2

462.

00C

OM

PRES

SOR

STR

UC

TUR

ES30

-R4

02,

304,

521.

77

1,

452,

445

852,

077

61

,839

2.68

13.8

463.

00M

EASU

RIN

G &

REG

ULA

TIN

G S

TRU

CTU

RES

30-R

30

1,28

4,37

6.57

833,

969

45

0,40

8

32,7

532.

55

13

.846

5.00

MAI

NS

60-R

30

143,

097,

429.

44

60,0

81,9

92

83,0

15,4

37

1,79

6,72

41.

26

46

.246

6.00

CO

MPR

ESSO

R E

QU

IPM

ENT

30-R

2.5

020

,215

,232

.38

13

,386

,766

6,

828,

466

447,

913

2.22

15.2

467.

00M

EASU

RIN

G &

REG

ULA

TIN

G E

QU

IPM

ENT

25-R

20

7,55

6,45

7.78

3,86

2,84

6

3,

693,

612

225,

453

2.98

16.4

468.

00C

OM

MU

NIC

ATIO

N S

TRU

CTU

RES

& E

QU

IPM

ENT

15-R

20

2,97

0,57

9.61

2,22

2,83

9

74

7,74

1

75,3

632.

54

9.

946

9.00

OTH

ER40

-SQ

01,

943.

15

934

1,00

9

32

1.65

31.5

TOTA

L TR

ANSM

ISSI

ON

PLA

NT

178,

601,

272.

81

81,8

41,7

91

96,7

59,4

82

2,67

2,41

5

DIS

TRIB

UTI

ON

PLA

NT

471.

00LA

ND

RIG

HTS

75-R

40

34,2

78.4

9

-

34,2

78

960

2.80

35.7

472.

00ST

RU

CTU

RES

& IM

PRO

VEM

ENTS

30-R

30

226,

431.

05

90,1

48

13

6,28

3

10,8

694.

80

12

.547

3.00

SER

VIC

ES50

-R2.

50

24,3

01,6

66.4

0

12,2

09,6

33

12,0

92,0

33

321,

866

1.32

37.6

474.

00H

OU

SE R

EG. I

NST

ALLA

TIO

NS

30-R

20

3,88

0,68

1.36

1,82

0,35

7

2,

060,

324

124,

165

3.20

16.6

475.

00M

AIN

S60

-R3

029

,365

,029

.68

12

,842

,216

16

,522

,814

37

8,70

01.

29

43

.647

7.00

MEA

SUR

ING

& R

EGU

LATI

NG

EQ

UIP

MEN

T20

-R3

028

7,35

9.98

15

9,84

1

127,

519

25

,504

8.88

5.0

(*)

478.

00M

ETER

S25

-R2

04,

453,

752.

42

2,

008,

268

2,44

5,48

4

30

4,01

96.

83

8.

047

9.00

OTH

ER D

IST.

EQ

UIP

MEN

TS35

-SQ

030

,514

.62

(133

,241

)

163,

756

6,

426

21.0

6

25

.5

TOTA

L D

ISTR

IBU

TIO

N P

LAN

T62

,579

,714

.00

28

,997

,222

33

,582

,492

1,

172,

509

GEN

ERAL

PLA

NT

481.

00LA

ND

RIG

HTS

75-R

40

350.

00

-

350

10

2.86

35.0

482.

00ST

RU

CTU

RES

& IM

PRO

VEM

ENTS

25-R

20

5,64

9,04

2.88

2,50

7,88

0

3,

141,

163

196,

864

3.48

16.0

483.

00O

FFIC

E FU

RN

ITU

RE

/ EQ

UIP

MEN

T15

-SQ

081

5,78

0.97

19

5,08

5

620,

696

76

,325

9.36

8.1

484.

00TR

ANSP

OR

T EQ

UIP

MEN

T7-

L1.5

+20

2,39

2,99

5.27

(177

,222

)

2,09

1,61

8

41

8,32

417

.48

5.0

(*)

485.

00H

EAVY

WO

RK

EQU

IPM

ENT

15-R

2+1

52,

996,

294.

91

1,

017,

302

1,52

9,54

9

13

9,76

74.

66

10

.948

6.00

TOO

LS /

WO

RK

EQU

IPM

ENT

20-S

Q0

2,53

7,09

3.34

582,

791

1,

954,

302

378,

615

14.9

2

5.

248

7.00

CO

MPU

TER

EQ

UIP

MEN

T5-

SQ0

1,45

3,69

2.03

656,

324

79

7,36

8

159,

474

10.9

7

5.

0(*

)48

8.00

CO

MM

UN

ICAT

ION

STR

UC

TUR

ES &

EQ

UIP

.14

-SQ

063

5,35

6.79

42

5,43

0

209,

927

38

,120

6.00

5.5

489.

00G

ENER

AL E

QU

IPM

ENT

20-S

Q0

2,00

0.00

53

5

1,

465

195

9.75

7.5

TOTA

L G

ENER

AL P

LAN

T16

,482

,606

.19

5,

208,

125

10,3

46,4

38

1,40

7,69

4

TOTA

L D

EPR

ECIA

BLE

PLAN

T25

7,69

6,79

3.00

11

6,05

6,52

3

140,

712,

227

5,25

3,50

02.

04

PLAN

T N

OT

STU

DIE

D46

0.00

LAN

D96

,699

.61

470.

00LA

ND

552.

35

48

0.00

LAN

D29

5,00

4.13

TOTA

L N

ON

- D

EPR

ECIA

BLE

PLAN

T39

2,25

6.09

TOTA

L PL

ANT

258,

089,

049.

09

116,

056,

523

14

0,71

2,22

7

5,

253,

500

(*) t

he re

mai

ning

life

in th

is a

ccou

nt h

as b

een

adju

sted

to 5

yea

rs to

avo

id la

rge

adju

stm

ents

in fu

ture

stu

dies

CAL

CU

LATE

D A

NN

UAL

PAC

IFIC

NO

RTH

ERN

GAS

LTD

.

SCH

EDU

LE 1

A - E

STIM

ATED

SU

RVI

VOR

CU

RVE

, OR

IGIN

AL C

OST

, BO

OK

DEP

REC

IATI

ON

RES

ERVE

AN

D C

ALC

ULA

TED

ANN

UAL

DEP

REC

IATI

ON

AC

CR

UAL

S R

ELAT

ED T

O U

TILI

TY P

LAN

T AT

DEC

EMB

ER 3

1, 2

009

LIFE

AN

ALYS

IS

WES

T SY

STEM

III-4

OR

IGIN

AL C

OST

BO

OK

CO

MPO

SITE

SUR

VIVO

RN

ETAT

DEP

REC

IATI

ON

FUTU

RE

ACC

RU

ALAC

CR

UAL

R

EMAI

NIN

G

DEP

REC

IAB

LE W

OR

KC

UR

VESA

LVAG

ED

ECEM

BER

31,

200

9R

ESER

VEAC

CR

UAL

SAM

OU

NT

RAT

ELI

FE(1

)(2

)(3

)(4

)(5

)(6

)(7

)(8

)=(7

)/(4)

(9)=

(6)/(

7)

TRAN

SMIS

SIO

N P

LAN

T46

1.00

LAN

D R

IGH

TS75

-R4

010

,967

.40

-

10

,967

19

7

1.80

55.7

463.

00M

EA

SU

RIN

G &

RE

GU

LATI

NG

STR

UC

TUR

ES

30-R

30

62,7

38.8

2

13

,554

49,1

85

2,26

1

3.

60

21

.846

5.00

MA

INS

60-R

30

2,00

2,74

5.02

1,03

7,69

1

96

5,05

4

22,6

97

1.13

42.5

467.

00M

EA

SU

RIN

G &

RE

GU

LATI

NG

EQ

UIP

ME

NT

25-R

20

893,

686.

82

178,

978

71

4,70

9

43,9

64

4.92

16.3

468.

00C

OM

MU

NIC

ATI

ON

STR

UC

TUR

ES

& E

QU

IPM

EN

T15

-R2

012

9,79

3.96

98

,364

31,4

30

6,28

6

4.

84

5.

0(*

)46

9.00

OTH

ER

40-S

Q0

18,4

50.4

6

3,

875

14,5

75

448

2.

43

32

.5

TOTA

L TR

AN

SM

ISS

ION

PLA

NT

3,11

8,38

2.48

1,33

2,46

2

1,

785,

920

75,8

53

DIS

TRIB

UTI

ON

PLA

NT

471.

00LA

ND

RIG

HTS

75-R

40

64,8

94.9

4

-

64,8

95

1,41

1

2.

17

46

.047

2.00

STR

UC

TUR

ES

& IM

PR

OV

EM

EN

TS30

-R3

050

6,65

0.60

14

8,47

9

358,

172

19

,033

3.

76

18

.847

3.00

SE

RV

ICE

S50

-R2.

50

4,53

1,30

6.46

1,14

1,46

0

3,

389,

846

95,3

98

2.11

35.5

474.

00H

OU

SE

RE

G. I

NS

TALL

ATI

ON

S30

-R2

02,

884,

072.

60

1,

054,

078

1,82

9,99

5

12

0,99

2

4.20

15.1

475.

00M

AIN

S60

-R3

08,

168,

387.

10

2,

165,

341

6,00

3,04

6

12

8,95

8

1.58

46.6

477.

00M

EA

SU

RIN

G &

RE

GU

LATI

NG

EQ

UIP

ME

NT

20-R

30

504,

571.

80

320,

246

18

4,32

6

36,8

65

7.31

5.0

(*)

478.

00M

ETE

RS

25-R

20

596,

260.

07

94,7

97

50

1,46

3

44,7

19

7.50

11.2

TOTA

L D

ISTR

IBU

TIO

N P

LAN

T17

,256

,143

.57

4,

924,

401

12,3

31,7

43

447,

376

GEN

ERAL

PLA

NT

482.

00S

TRU

CTU

RE

S &

IMP

RO

VE

ME

NTS

25-R

20

386,

892.

75

205,

665

18

1,22

8

22,3

38

5.77

8.1

483.

00O

FFIC

E F

UR

NIT

UR

E /

EQ

UIP

ME

NT

15-S

Q0

89,1

33.5

1

39

,750

49,3

84

4,77

7

5.

36

10

.348

4.00

TRA

NS

PO

RT

EQ

UIP

ME

NT

7-L1

.5+2

041

0,34

5.30

37

5,90

0

(47,

623)

-

-

0.

048

5.00

HE

AV

Y W

OR

K E

QU

IPM

EN

T15

-R2

+15

961,

219.

77

242,

481

57

4,55

6

44,9

72

4.68

12.8

486.

00TO

OLS

/ W

OR

K E

QU

IPM

EN

T20

-SQ

060

0,84

5.56

28

8,35

2

312,

494

40

,277

6.

70

7.

848

7.00

CO

MP

UTE

R E

QU

IPM

EN

T5-

SQ

074

,429

.11

74,4

29

0

-

-

0.0

488.

00C

OM

MU

NIC

ATI

ON

STR

UC

TUR

ES

& E

QU

IP.

14-S

Q0

151,

654.

01

121,

186

30

,468

4,

855

3.20

6.3

TOTA

L G

EN

ER

AL

PLA

NT

2,67

4,52

0.01

1,34

7,76

3

1,

100,

506

117,

219

TOTA

L D

EP

RE

CIA

BLE

PLA

NT

23,0

49,0

46.0

6

7,60

4,62

6

15

,218

,169

64

0,44

8

2.78

PLAN

T N

OT

STU

DIE

D46

0.00

LAN

D4,

586.

16

47

0.00

LAN

D25

,348

.00

480.

00LA

ND

650.

01

TOTA

L N

ON

- D

EP

RE

CIA

BLE

PLA

NT

30,5

84.1

7

TOTA

L P

LAN

T23

,079

,630

.23

7,

604,

626

15,2

18,1

69

640,

448

(*) t

he re

mai

ning

life

in th

is a

ccou

nt h

as b

een

adju

sted

to 5

yea

rs to

avo

id la

rge

adju

stm

ents

in fu

ture

stu

dies

CAL

CU

LATE

D A

NN

UAL

PAC

IFIC

NO

RTH

ERN

GAS

(N.E

.) LT

D.

SCH

EDU

LE 1

B -

ESTI

MAT

ED S

UR

VIVO

R C

UR

VE, O

RIG

INAL

CO

ST, B

OO

K D

EPR

ECIA

TIO

N R

ESER

VE A

ND

CAL

CU

LATE

DAN

NU

AL D

EPR

ECIA

TIO

N A

CC

RU

ALS

REL

ATED

TO

UTI

LITY

PLA

NT

AT D

ECEM

BER

31,

200

9

LIFE

AN

ALYS

IS

DAW

SON

CR

EEK

III-5

OR

IGIN

AL

CO

STB

OO

KC

OM

POSI

TESU

RVI

VOR

NET

AT

DEP

REC

IATI

ON

FUTU

RE

AC

CR

UA

LA

CC

RU

AL

REM

AIN

ING

D

EPR

ECIA

BLE

WO

RK

CU

RVE

SALV

AG

ED

ECEM

BER

31,

200

9R

ESER

VEA

CC

RU

ALS

AM

OU

NT

RA

TELI

FE(1

)(2

)(3

)(4

)(5

)(6

)(7

)(8

)=(7

)/(4)

(9)=

(6)/(

7)

TRA

NSM

ISSI

ON

PLA

NT

461.

00LA

ND

RIG

HTS

75-R

40

52,5

45.0

7

37

,751

14,7

94

240

0.

46

61

.646

2.00

CO

MPR

ESSO

R S

TRU

CTU

RES

30-R

40

465,

044.

89

156,

998

30

8,04

7

16,4

60

3.54

18.7

463.

00M

EASU

RIN

G &

REG

ULA

TIN

G S

TRU

CTU

RES

30-R

30

74,9

79.5

4

21

,550

53,4

30

3,07

1

4.

10

17

.446

5.00

MAI

NS

60-R

30

3,44

7,31

8.91

1,61

7,87

7

1,

829,

442

37,5

42

1.09

48.7

467.

00M

EASU

RIN

G &

REG

ULA

TIN

G E

QU

IPM

ENT

25-R

20

3,11

9,66

7.93

1,26

3,36

5

1,

856,

303

107,

412

3.

44

17

.3

TOTA

L TR

ANSM

ISSI

ON

PLA

NT

7,15

9,55

6.34

3,09

7,54

1

4,

062,

015

164,

725

DIS

TRIB

UTI

ON

PLA

NT

471.

00LA

ND

RIG

HTS

75-R

40

141,

336.

68

4,93

6

13

6,40

1

2,20

9

1.

56

61

.747

2.00

STR

UC

TUR

ES &

IMPR

OVE

MEN

TS30

-R3

085

6,31

0.50

13

0,08

9

726,

222

30

,325

3.

54

23

.947

3.00

SER

VIC

ES50

-R2.

50

11,5

51,8

26.9

7

2,22

6,43

7

9,

325,

390

224,

952

1.

95

41

.547

4.00

HO

USE

REG

. IN

STAL

LATI

ON

S30

-R2

01,

525,

186.

55

53

6,22

1

988,

966

44

,757

2.

93

22

.147

5.00

MAI

NS

60-R

30

15,8

84,0

60.3

8

4,41

2,32

4

11

,471

,736

22

1,81

8

1.40

51.7

476.

00C

OM

PRES

SOR

EQ

UIP

MEN

T30

-R2.

50

305.

01

68

23

7

13

4.

26

18

.247

7.00

MEA

SUR

ING

& R

EGU

LATI

NG

EQ

UIP

MEN

T20

-R3

066

8,22

2.50

31

0,58

4

357,

639

33

,724

5.

05

10

.647

8.00

MET

ERS

25-R

20

1,31

0,60

2.04

331,

094

97

9,50

8

59,8

51

4.57

16.4

479.

00O

THER

DIS

T. E

QU

IPM

ENTS

35-S

Q0

19,6

16.7

0

6,

493

13,1

24

558

2.

84

23

.5

TOTA

L D

ISTR

IBU

TIO

N P

LAN

T31

,957

,467

.33

7,

958,

246

23,9

99,2

21

618,

207

GEN

ERA

L PL

AN

T48

1.00

LAN

D R

IGH

TS75

-R4

01,

337.

59

17

8

1,16

0

19

1.42

61.1

482.

00ST

RU

CTU

RES

& IM

PRO

VEM

ENTS

25-R

20

784,

877.

51

339,

303

44

5,57

5

30,1

77

3.84

14.8

483.

00O

FFIC

E FU

RN

ITU

RE

/ EQ

UIP

MEN

T15

-SQ

015

5,25

6.76

15

5,25

7

(0)

-

-

0.0

484.

00TR

ANSP

OR

T EQ

UIP

MEN

T7-

L1.5

+20

730,

456.

23

568,

939

15

,425

2,

775

0.38

5.6

485.

00H

EAVY

WO

RK

EQU

IPM

ENT

15-R

2+1

512

0,87

0.88

12

7

102,

613

10

,155

8.

40

10

.148

6.00

TOO

LS /

WO

RK

EQU

IPM

ENT

20-S

Q0

486,

813.

73

237,

057

24

9,75

7

21,3

30

4.38

11.7

487.

00C

OM

PUTE

R E

QU

IPM

ENT

5-SQ

076

8,89

3.54

54

2,21

1

226,

683

45

,337

5.

90

5.

0(*

)48

8.00

CO

MM

UN

ICAT

ION

STR

UC

TUR

ES &

EQ

UIP

.14

-SQ

011

1,95

1.62

54

,857

57,0

95

11,4

19

10.2

0

5.0

(*)

TOTA

L G

ENER

AL P

LAN

T3,

160,

457.

86

1,

897,

929

1,09

8,30

6

12

1,21

1

TOTA

L D

EPR

ECIA

BLE

PLAN

T42

,277

,481

.53

12

,953

,716

29

,159

,542

90

4,14

3

2.14

PLA

NT

NO

T ST

UD

IED

460.

00LA

ND

6,39

5.28

470.

00LA

ND

11,9

16.3

6

48

0.00

LAN

D76

,502

.87

TOTA

L N

ON

- D

EPR

ECIA

BLE

PLAN

T94

,814

.51

TOTA

L PL

ANT

42,3

72,2

96.0

4

12,9

53,7

16

29,1

59,5

42

904,

143

(*) t

he re

mai

ning

life

in th

is a

ccou

nt h

as b

een

adju

sted

to 5

yea

rs to

avo

id la

rge

adju

stm

ents

in fu

ture

stu

dies

CA

LCU

LATE

D A

NN

UA

L

PAC

IFIC

NO

RTH

ERN

GA

S (N

.E.)

LTD

.

SCH

EDU

LE 1

C -

ESTI

MA

TED

SU

RVI

VOR

CU

RVE

, OR

IGIN

AL

CO

ST, B

OO

K D

EPR

ECIA

TIO

N R

ESER

VE A

ND

CA

LCU

LATE

DA

NN

UA

L D

EPR

ECIA

TIO

N A

CC

RU

ALS

REL

ATE

D T

O U

TILI

TY P

LAN

T A

T D

ECEM

BER

31,

200

9

LIFE

AN

ALY

SIS

FOR

T ST

. JO

HN

III-6

OR

IGIN

AL

CO

STB

OO

KC

OM

POSI

TESU

RVI

VOR

NET

AT

DEP

REC

IATI

ON

FUTU

RE

AC

CR

UA

LA

CC

RU

AL

REM

AIN

ING

D

EPR

ECIA

BLE

WO

RK

CU

RVE

SALV

AG

ED

ECEM

BER

31,

200

9R

ESER

VEA

CC

RU

ALS

AM

OU

NT

RA

TELI

FE(1

)(2

)(3

)(4

)(5

)(6

)(7

)(8

)=(7

)/(4)

(9)=

(6)/(

7)

GA

THER

ING

PLA

NT

411.

00LA

ND

RIG

HTS

75-R

40

275.

00

-

27

5

6

2.

18

45

.841

2.00

STR

UC

TUR

ES

& IM

PR

OV

EM

EN

TS30

-R3

034

,442

.84

10,6

28

23

,815

1,

893

5.50

12.6

413.

00M

EA

SU

RIN

G &

RE

GU

LATI

NG

STR

UC

TUR

ES

30-R

30

75,1

59.7

1

49

,605

25,5

55

4,06

3

5.

41

6.

341

7.00

ME

AS

UR

ING

& R

EG

ULA

TIN

G E

QU

IPM

EN

T25

-R2

029

,701

.25

8,01

9

21

,682

1,

282

4.32

16.9

418.

00P

UR

IFIC

ATI

ON

EQ

UIP

ME

NT

25-R

30

3,23

5,62

9.21

2,54

4,24

6

69

1,38

3

34,1

02

1.05

20.3

TOTA

L G

ATH

ER

ING

PLA

NT

3,37

5,20

8.01

2,61

2,49

8

76

2,71

0

41,3

46

TRA

NSM

ISSI

ON

PLA

NT

465.

00M

AIN

S60

-R3

01,

716,

135.

43

87

9,87

4

836,

261

25

,393

1.

48

32

.946

6.00

CO

MP

RE

SS

OR

EQ

UIP

ME

NT

30-R

2.5

04,

412.

00

1,

985

2,42

7

18

1

4.10

13.4

467.

00M

EA

SU

RIN

G &

RE

GU

LATI

NG

EQ

UIP

ME

NT

25-R

20

104,

750.

03

27,6

40

77

,110

5,

236

5.00

14.7

TOTA

L TR

AN

SM

ISS

ION

PLA

NT

1,82

5,29

7.46

909,

499

91

5,79

8

30,8

10

DIS

TRIB

UTI

ON

PLA

NT

471.

00LA

ND

RIG

HTS

75-R

40

2,01

0.63

-

2,

011

42

2.

09

47

.947

2.00

STR

UC

TUR

ES

& IM

PR

OV

EM

EN

TS30

-R3

022

5,39

4.32

29

,514

195,

880

8,

448

3.75

23.2

473.

00S

ER

VIC

ES

50-R

2.5

059

0,69

8.63

23

2,78

9

357,

910

11

,957

2.

02

29

.947

4.00

HO

US

E R

EG

. IN

STA

LLA

TIO

NS

30-R

20

263,

197.

16

184,

652

78

,545

8,

038

3.05

9.8

475.

00M

AIN

S60

-R3

098

4,29

6.45

44

4,88

8

539,

408

16

,117

1.

64

33

.547

7.00

ME

AS

UR

ING

& R

EG

ULA

TIN

G E

QU

IPM

EN

T20

-R3

019

3,79

0.89

16

1,47

5

32,3

16

6,46

3

3.

34

5.

0(*

)47

8.00

ME

TER

S25

-R2

024

8,02

8.51

15

7,89

8

90,1

31

13,5

25

5.45

6.7

TOTA

L D

ISTR

IBU

TIO

N P

LAN

T2,

507,

416.

59

1,

211,

216

1,29

6,20

1

64

,590

GEN

ERA

L PL

AN

T48

2.00

STR

UC

TUR

ES

& IM

PR

OV

EM

EN

TS25

-R2

040

2,31

2.36

34

9,72

4

52,5

88

10,1

56

2.52

5.2

483.

00O

FFIC

E F

UR

NIT

UR

E /

EQ

UIP

ME

NT

15-S

Q0

30,9

72.2

2

15

,683

15,2

89

1,80

0

5.

81

8.

548

4.00

TRA

NS

PO

RT

EQ

UIP

ME

NT

7-L1

.5+2

081

,540

.77

81,5

40

(1

6,30

7)

-

-

0.0

485.

00H

EA

VY

WO

RK

EQ

UIP

ME

NT

15-R

2+1

510

1,77

7.10

32

,371

54,1

40

3,80

9

3.

74

14

.248

6.00

TOO

LS /

WO

RK

EQ

UIP

ME

NT

20-S

Q0

90,9

78.4

7

49

,495

41,4

83

6,05

9

6.

66

6.

848

7.00

CO

MP

UTE

R E

QU

IPM

EN

T5-

SQ

026

,257

.84

26,2

58

(0

)

-

-

0.

048

8.00

CO

MM

UN

ICA

TIO

N S

TRU

CTU

RE

S &

EQ

UIP

.14

-SQ

011

7,37

7.59

11

4,23

3

3,14

5

27

3

0.23

11.5

TOTA

L G

EN

ER

AL

PLA

NT

851,

216.

35

669,

304

15

0,33

8

22,0

97

TOTA

L D

EP

RE

CIA

BLE

PLA

NT

8,55

9,13

8.41

5,40

2,51

7

3,

125,

048

158,

843

1.

86

PLA

NT

NO

T ST

UD

IED

410.

00LA

ND

3,08

9.40

460.

00LA

ND

-

470.

00LA

ND

-

480.

00LA

ND

22,8

96.1

3

TOTA

L N

ON

- D

EP

RE

CIA

BLE

PLA

NT

25,9

85.5

3

TOTA

L P

LAN

T8,

585,

123.

94

5,

402,

517

3,12

5,04

8

15

8,84

3

(*) t

he re

mai

ning

life

in th

is a

ccou

nt h

as b

een

adju

sted

to 5

yea

rs to

avo

id la

rge

adju

stm

ents

in fu

ture

stu

dies

CA

LCU

LATE

D A

NN

UA

L

PAC

IFIC

NO

RTH

ERN

GA

S (N

.E.)

LTD

.

SCH

EDU

LE 1

D -

ESTI

MA

TED

SU

RVI

VOR

CU

RVE

, OR

IGIN

AL

CO

ST, B

OO

K D

EPR

ECIA

TIO

N R

ESER

VE A

ND

CA

LCU

LATE

DA

NN

UA

L D

EPR

ECIA

TIO

N A

CC

RU

ALS

REL

ATE

D T

O U

TILI

TY P

LAN

T A

T D

ECEM

BER

31,

200

9

LIFE

AN

ALY

SIS

TUM

BLE

R R

IDG

E

III-7

Acco

unt

Des

crip

tion

Cur

rent

Te

rase

n G

as In

c.Al

taga

s U

tiliti

es In

c.M

anito

ba H

ydro

- G

as A

sset

sAT

CO

Gas

Gaz

ifere

New

Rec

omm

enda

tion

443.

00G

as H

old

ers

– S

tora

ge

* 40

-SQ

N

/A

N/A

40

-SQ

449.

00O

ther

Loc

al S

tora

ge E

quip

men

t *

35-

R3

N/A

N/A

33-

R3

461.

00La

nd R

ight

s *

75-

R4

65-R

4

75-R

4

75-

R4

462.

00C

ompr

esso

r Stru

ctur

es *

30-

R4

N/A

N/A

30-

R4

463.

00M

easu

ring

& R

egul

atin

g St

ruct

ures

*

30-

R2.

5 4

5-R

4 4

5-R

3 3

0-R

3

465.

00M

ains

43-R

4 6

0-R

3 6

0-L3

65-

S2.5

60-

R3

466.

00C

ompr

esso

r Eq

uipm

ent

30-R

433

-R3

N/A

N/A

N/A

N/A

467.

00M

easu

ring

& R

egul

atin

g Eq

uipm

ent

25-L

3 2

5-R

2.5

33-

S2.5

40-

S3 2

5-R

2

468.

00C

omm

unic

atio

n St

ruct

ures

&

Equi

pmen

t17

-R4

15-

R2

N/A

N/A

15-

R2

469.

00O

ther

* N

/A N

/A 4

0-SQ

40-

SQ47

1.00

Land

Rig

hts

*75

-R4

65-

R4

75-

R4

100-

R5

75-

R4

472.

00St

ruct

ures

& Im

prov

emen

ts 3

3-R

3 2

8-L1

46-

R3

40-

R1

55-R

2.5

30-

R3

473.

00Se

rvic

es 3

7-R

3 5

5-R

2.5

44-

R4

50-

R2.

552

-R2.

550

-R5

50-

R2.

547

4.00

Hou

se R

eg. I

nsta

llatio

ns 3

6-R

3 3

0-R

2 4

1-R

3 4

0-R

445

-R4

30-

R2

475.

00M

ains

* 6

0-R

3 5

5-R

265

-R3

62-R

2.5

75-R

4 6

0-R

347

7.00

Mea

surin

g &

Reg

ulat

ing

Equi

pmen

t 3

3-R

315

-R2.

5 4

0-R

4 3

1-R

238

-R2

30-R

4 2

0-R

3

478.

00M

eter

s 3

4-R

5 2

5-R

2 3

4-R

2.5

28-

R3

25-R

2.5

12-R

1.5

25-

R2

479.

00O

ther

Dis

t. Eq

uipm

ents

* N

/A N

/A N

/A 3

5-SQ

481.

00La

nd R

ight

s *

N/A

N/A

N/A

75-

R4

482.

00St

ruct

ures

& Im

prov

emen

ts 3

6-R

325

-R2

75-

R2

22-

R3

40-S

1 2

5-R

248

3.00

Offi

ce F

urni

ture

/ Eq

uipm

ent

*15

-SQ

20-

SQ 1

5-SQ

20-S

Q15

-SQ

15-

SQ

484.

00Tr

ansp

ort E

quip

men

t 7

-R1

6-L1

7-L

1.5

8-R

39-

L1.5

9-S3

7-L

1.5

485.

00H

eavy

Wor

k Eq

uipm

ent

14-

S4 1

5-R

2 1

6-L0

.5 1

5-L1

.5

13-L

2.5

15-S

3 1

5-R

2

486.

00To

ols

/ Wor

k Eq

uipm

ent

27-

R4

20-

SQ 2

0-SQ

15-

SQ20

-SQ

10-S

Q 2

0-SQ

487.

00C

ompu

ter E

quip

men

t 7

-S3

5-S

Q 3

-SQ

/4-S

Q/

5-S

Q4-

SQ 5

-SQ

488.

00C

omm

unic

atio

n St

ruct

ures

&

Equi

p. 1

4-S6

15-

SQ5-

SQ

10-

SQ17

-L2.

510

-L0

14-

SQ

489.

00G

ener

al E

quip

men

t *

N/A

N/A

10-

SQ25

-SQ

N/A

20-

SQ

* A

ccou

nt d

etai

l not

incl

uded

in la

st D

epre

ciat

ion

Stu

dy.

Pac

ific

Nor

ther

n G

as L

td.

Sch

edul

e 2

- Sum

mar

y of

Pee

r Ave

rage

Ser

vice

Life

Est

imat

es

III-8

PART IV. SERVICE LIFE STATISTICS

IV-2

PACIFIC NORTHERN GAS LTD.

ACCOUNT 462.00 COMPRESSOR STRUCTURES

ORIGINAL LIFE TABLE

PLACEMENT BAND 1969-2008 EXPERIENCE BAND 1995-2008

AGE AT EXPOSURES AT RETIREMENTS PCT SURV BEGIN OF BEGINNING OF DURING AGE RETMT SURV BEGIN OF INTERVAL AGE INTERVAL INTERVAL RATIO RATIO INTERVAL

0.0 728,761 2 0.0000 1.0000 100.00 0.5 794,251 0.0000 1.0000 100.00 1.5 815,058 0.0000 1.0000 100.00 2.5 652,117 0.0000 1.0000 100.00 3.5 686,771 0.0000 1.0000 100.00 4.5 700,087 41 0.0001 0.9999 100.00 5.5 784,468 19 0.0000 1.0000 99.99 6.5 876,516 0.0000 1.0000 99.99 7.5 526,483 0.0000 1.0000 99.99 8.5 591,086 0.0000 1.0000 99.99

9.5 628,964 0.0000 1.0000 99.99 10.5 703,492 0.0000 1.0000 99.99 11.5 745,048 53 0.0001 0.9999 99.99 12.5 1,542,811 35 0.0000 1.0000 99.98 13.5 1,542,776 13 0.0000 1.0000 99.98 14.5 1,472,532 65 0.0000 1.0000 99.98 15.5 1,437,584 46 0.0000 1.0000 99.98 16.5 1,427,181 212 0.0001 0.9999 99.98 17.5 1,384,679 265 0.0002 0.9998 99.97 18.5 1,360,590 117 0.0001 0.9999 99.95

19.5 1,271,141 817 0.0006 0.9994 99.94 20.5 1,178,586 194 0.0002 0.9998 99.88 21.5 1,146,194 453 0.0004 0.9996 99.86 22.5 954,057 301 0.0003 0.9997 99.82 23.5 916,311 6,777 0.0074 0.9926 99.79 24.5 836,264 0.0000 1.0000 99.05 25.5 829,194 1 0.0000 1.0000 99.05 26.5 38,154 16 0.0004 0.9996 99.05 27.5 38,138 0.0000 1.0000 99.01 28.5 38,031 0.0000 1.0000 99.01

29.5 36,870 5 0.0001 0.9999 99.01 30.5 36,865 6 0.0002 0.9998 99.00 31.5 36,859 2 0.0001 0.9999 98.98 32.5 36,637 27 0.0007 0.9993 98.97 33.5 36,351 6 0.0002 0.9998 98.90 34.5 36,283 9 0.0002 0.9998 98.88 35.5 35,391 35 0.0010 0.9990 98.86 36.5 35,186 1,741 0.0495 0.9505 98.76 37.5 33,216 0.0000 1.0000 93.87 38.5 32,444 0.0000 1.0000 93.87 39.5 93.87

IV-3

IV-4


ACCOUNT 463.00 MEASURING & REGULATING STRUCTURES

ORIGINAL LIFE TABLE



0.0 161,735 9 0.0001 0.9999 100.00 0.5 308,706 5 0.0000 1.0000 99.99 1.5 335,731 4 0.0000 1.0000 99.99 2.5 440,228 228 0.0005 0.9995 99.99 3.5 459,476 243 0.0005 0.9995 99.94 4.5 472,570 422 0.0009 0.9991 99.89 5.5 444,130 333 0.0007 0.9993 99.80 6.5 669,185 135 0.0002 0.9998 99.73 7.5 684,841 68 0.0001 0.9999 99.71 8.5 670,200 1,255 0.0019 0.9981 99.70

9.5 707,475 800 0.0011 0.9989 99.51 10.5 757,130 130 0.0002 0.9998 99.40 11.5 776,838 750 0.0010 0.9990 99.38 12.5 1,022,244 882 0.0009 0.9991 99.28 13.5 1,029,659 984 0.0010 0.9990 99.19 14.5 882,524 4,061 0.0046 0.9954 99.09 15.5 828,159 1,837 0.0022 0.9978 98.63 16.5 674,563 183 0.0003 0.9997 98.41 17.5 644,861 1,166 0.0018 0.9982 98.38 18.5 624,879 154 0.0002 0.9998 98.20

19.5 625,560 94 0.0002 0.9998 98.18 20.5 407,103 391 0.0010 0.9990 98.16 21.5 391,524 662 0.0017 0.9983 98.06 22.5 393,531 448 0.0011 0.9989 97.89 23.5 363,855 2,707 0.0074 0.9926 97.78 24.5 330,726 835 0.0025 0.9975 97.06 25.5 362,995 887 0.0024 0.9976 96.82 26.5 123,524 1,897 0.0154 0.9846 96.59 27.5 113,621 5,808 0.0511 0.9489 95.10 28.5 103,240 1,255 0.0122 0.9878 90.24

29.5 100,229 45 0.0004 0.9996 89.14 30.5 99,908 90 0.0009 0.9991 89.10 31.5 98,294 68 0.0007 0.9993 89.02 32.5 95,285 153 0.0016 0.9984 88.96 33.5 89,736 170 0.0019 0.9981 88.82 34.5 85,845 174 0.0020 0.9980 88.65 35.5 77,916 409 0.0052 0.9948 88.47 36.5 69,593 1,210 0.0174 0.9826 88.01 37.5 60,891 0.0000 1.0000 86.48 38.5 44,570 0.0000 1.0000 86.48 39.5 86.48

IV-5

IV-6


ACCOUNT 465.00 MAINS

ORIGINAL LIFE TABLE



0.0 59,338,240 426 0.0000 1.0000 100.00 0.5 60,529,563 6,314 0.0001 0.9999 100.00 1.5 62,342,858 5,556 0.0001 0.9999 99.99 2.5 60,775,872 2,268 0.0000 1.0000 99.98 3.5 55,783,904 5,771 0.0001 0.9999 99.98 4.5 62,224,809 12,750 0.0002 0.9998 99.97 5.5 61,765,127 13,801 0.0002 0.9998 99.95 6.5 63,230,128 9,186 0.0001 0.9999 99.93 7.5 35,310,845 17,030 0.0005 0.9995 99.92 8.5 33,965,370 24,072 0.0007 0.9993 99.87

9.5 34,029,103 12,029 0.0004 0.9996 99.80 10.5 34,654,879 16,402 0.0005 0.9995 99.76 11.5 35,778,171 19,110 0.0005 0.9995 99.71 12.5 57,605,901 23,610 0.0004 0.9996 99.66 13.5 58,549,747 6,266 0.0001 0.9999 99.62 14.5 53,399,005 19,754 0.0004 0.9996 99.61 15.5 48,805,319 103,108 0.0021 0.9979 99.57 16.5 46,096,817 166,972 0.0036 0.9964 99.36 17.5 44,291,875 13,756 0.0003 0.9997 99.00 18.5 36,748,319 16,037 0.0004 0.9996 98.97

19.5 36,168,190 33,662 0.0009 0.9991 98.93 20.5 34,119,959 10,627 0.0003 0.9997 98.84 21.5 33,553,287 4,013 0.0001 0.9999 98.81 22.5 29,413,920 7,517 0.0003 0.9997 98.80 23.5 29,503,866 21,592 0.0007 0.9993 98.77 24.5 29,227,931 35,278 0.0012 0.9988 98.70 25.5 47,079,609 9,725 0.0002 0.9998 98.58 26.5 25,243,135 332,704 0.0132 0.9868 98.56 27.5 23,957,405 31,885 0.0013 0.9987 97.26 28.5 23,059,346 304,166 0.0132 0.9868 97.13

29.5 21,713,624 581,712 0.0268 0.9732 95.85 30.5 21,111,732 668 0.0000 1.0000 93.28 31.5 21,000,194 11,076 0.0005 0.9995 93.28 32.5 20,873,365 41,969 0.0020 0.9980 93.23 33.5 20,516,631 11,320 0.0006 0.9994 93.04 34.5 18,928,887 4,609 0.0002 0.9998 92.98 35.5 18,774,766 46 0.0000 1.0000 92.96 36.5 18,272,295 4,639 0.0003 0.9997 92.96 37.5 18,090,787 4,905 0.0003 0.9997 92.93 38.5 17,726,273 0.0000 1.0000 92.90 39.5 92.90

IV-7

IV-8


ACCOUNT 466.00 COMPRESSOR EQUIPMENT

ORIGINAL LIFE TABLE



0.0 5,338,945 4,237 0.0008 0.9992 100.00 0.5 5,967,166 1,804 0.0003 0.9997 99.92 1.5 6,247,389 1,860 0.0003 0.9997 99.89 2.5 6,253,744 5,963 0.0010 0.9990 99.86 3.5 6,552,734 1,751 0.0003 0.9997 99.76 4.5 6,226,067 6,929 0.0011 0.9989 99.73 5.5 6,488,332 1,864 0.0003 0.9997 99.62 6.5 6,947,099 6,195 0.0009 0.9991 99.59 7.5 4,165,063 4,856 0.0012 0.9988 99.50 8.5 5,727,946 2,225 0.0004 0.9996 99.38

9.5 6,100,883 8,923 0.0015 0.9985 99.34 10.5 6,834,131 6,644 0.0010 0.9990 99.19 11.5 7,243,861 19,493 0.0027 0.9973 99.09 12.5 15,274,874 22,594 0.0015 0.9985 98.82 13.5 15,252,281 18,382 0.0012 0.9988 98.67 14.5 14,599,935 66,758 0.0046 0.9954 98.55 15.5 14,203,116 16,517 0.0012 0.9988 98.10 16.5 14,088,295 34,103 0.0024 0.9976 97.98 17.5 13,652,789 31,429 0.0023 0.9977 97.74 18.5 13,395,519 406,318 0.0303 0.9697 97.52

19.5 12,141,654 17,709 0.0015 0.9985 94.57 20.5 11,253,293 5,482 0.0005 0.9995 94.43 21.5 10,943,759 47,287 0.0043 0.9957 94.38 22.5 9,077,381 4,066 0.0004 0.9996 93.97 23.5 8,718,372 80,410 0.0092 0.9908 93.93 24.5 7,944,229 2,105 0.0003 0.9997 93.07 25.5 7,953,823 397 0.0000 1.0000 93.04 26.5 445,088 911 0.0020 0.9980 93.04 27.5 444,177 2,242 0.0050 0.9950 92.85 28.5 440,919 348 0.0008 0.9992 92.39

29.5 429,547 524 0.0012 0.9988 92.32 30.5 429,023 1,895 0.0044 0.9956 92.21 31.5 427,128 82,670 0.1935 0.8065 91.80 32.5 342,365 182 0.0005 0.9995 74.04 33.5 339,719 905 0.0027 0.9973 74.00 34.5 338,230 3,093 0.0091 0.9909 73.80 35.5 326,754 169 0.0005 0.9995 73.13 36.5 324,972 7,455 0.0229 0.9771 73.09 37.5 315,338 63 0.0002 0.9998 71.42 38.5 307,954 0.0000 1.0000 71.41 39.5 71.41

IV-9

IV-10


ACCOUNT 467.00 MEASURING & REGULATING EQUIPMENT

ORIGINAL LIFE TABLE



0.0 3,183,004 409 0.0001 0.9999 100.00 0.5 3,637,800 5,790 0.0016 0.9984 99.99 1.5 3,531,437 3,504 0.0010 0.9990 99.83 2.5 3,938,085 2,317 0.0006 0.9994 99.73 3.5 3,872,718 7,547 0.0019 0.9981 99.67 4.5 3,495,907 7,227 0.0021 0.9979 99.48 5.5 3,378,930 4,577 0.0014 0.9986 99.27 6.5 4,106,686 2,634 0.0006 0.9994 99.13 7.5 2,475,967 5,953 0.0024 0.9976 99.07 8.5 2,233,592 3,104 0.0014 0.9986 98.83

9.5 2,359,060 6,024 0.0026 0.9974 98.69 10.5 2,521,267 3,258 0.0013 0.9987 98.43 11.5 2,584,086 4,537 0.0018 0.9982 98.30 12.5 3,398,247 4,818 0.0014 0.9986 98.12 13.5 3,420,978 15,077 0.0044 0.9956 97.98 14.5 2,919,785 5,544 0.0019 0.9981 97.55 15.5 2,749,159 6,635 0.0024 0.9976 97.36 16.5 2,244,381 4,932 0.0022 0.9978 97.13 17.5 2,142,554 6,576 0.0031 0.9969 96.92 18.5 2,074,163 2,412 0.0012 0.9988 96.62

19.5 2,074,298 10,555 0.0051 0.9949 96.50 20.5 1,346,744 2,520 0.0019 0.9981 96.01 21.5 1,293,685 2,338 0.0018 0.9982 95.83 22.5 1,299,147 6,347 0.0049 0.9951 95.66 23.5 1,195,663 7,918 0.0066 0.9934 95.19 24.5 1,084,564 2,636 0.0024 0.9976 94.56 25.5 1,195,575 3,053 0.0026 0.9974 94.33 26.5 409,372 3,541 0.0086 0.9914 94.08 27.5 379,550 2,004 0.0053 0.9947 93.27 28.5 362,533 2,797 0.0077 0.9923 92.78

29.5 353,971 844 0.0024 0.9976 92.07 30.5 352,219 939 0.0027 0.9973 91.85 31.5 346,281 1,798 0.0052 0.9948 91.60 32.5 334,826 4,619 0.0138 0.9862 91.12 33.5 312,494 16,443 0.0526 0.9474 89.86 34.5 283,836 1,087 0.0038 0.9962 85.13 35.5 257,295 2,886 0.0112 0.9888 84.81 36.5 228,431 3,081 0.0135 0.9865 83.86 37.5 200,757 496 0.0025 0.9975 82.73 38.5 146,687 387 0.0026 0.9974 82.52 39.5 82.31

IV-11

IV-12


ACCOUNT 468.00 COMMUNICATION STRUCTURES & EQUIPMENT

ORIGINAL LIFE TABLE



0.0 2,326,717 0.0000 1.0000 100.00 0.5 2,371,322 0.0000 1.0000 100.00 1.5 2,367,142 311 0.0001 0.9999 100.00 2.5 1,844,547 1,263 0.0007 0.9993 99.99 3.5 1,947,066 278 0.0001 0.9999 99.92 4.5 2,002,678 3,456 0.0017 0.9983 99.91 5.5 2,066,152 14,044 0.0068 0.9932 99.74 6.5 1,974,792 14,399 0.0073 0.9927 99.06 7.5 729,301 7,719 0.0106 0.9894 98.34 8.5 594,736 3,194 0.0054 0.9946 97.30

9.5 622,896 25,657 0.0412 0.9588 96.77 10.5 613,120 645 0.0011 0.9989 92.78 11.5 615,532 8,447 0.0137 0.9863 92.68 12.5 612,117 4,806 0.0079 0.9921 91.41 13.5 607,856 1,167 0.0019 0.9981 90.69 14.5 625,123 2,126 0.0034 0.9966 90.52 15.5 622,997 2,154 0.0035 0.9965 90.21 16.5 603,964 29,739 0.0492 0.9508 89.89 17.5 402,310 482 0.0012 0.9988 85.47 18.5 260,567 5,390 0.0207 0.9793 85.37

19.5 195,487 0.0000 1.0000 83.60 20.5 190,999 0.0000 1.0000 83.60 21.5 75,925 0.0000 1.0000 83.60 22.5 75,925 0.0000 1.0000 83.60 23.5 53,305 0.0000 1.0000 83.60 24.5 42,513 0.0000 1.0000 83.60 25.5 40,574 0.0000 1.0000 83.60 26.5 37,779 0.0000 1.0000 83.60 27.5 37,507 0.0000 1.0000 83.60 28.5 5,872 0.0000 1.0000 83.60 29.5 5,872 0.0000 1.0000 83.60 30.5 83.60

IV-13

IV-14


ACCOUNT 472.00 STRUCTURES & IMPROVEMENTS

ORIGINAL LIFE TABLE



0.0 3,376 0.0000 1.0000 100.00 0.5 3,376 0.0000 1.0000 100.00 1.5 23,863 22 0.0009 0.9991 100.00 2.5 23,841 2 0.0001 0.9999 99.91 3.5 84,552 0.0000 1.0000 99.90 4.5 100,108 0.0000 1.0000 99.90 5.5 332,958 0.0000 1.0000 99.90 6.5 376,705 0.0000 1.0000 99.90 7.5 376,521 0.0000 1.0000 99.90 8.5 376,521 0.0000 1.0000 99.90

9.5 376,521 0.0000 1.0000 99.90 10.5 376,521 5,287 0.0140 0.9860 99.90 11.5 376,834 0.0000 1.0000 98.50 12.5 382,547 21,846 0.0571 0.9429 98.50 13.5 360,701 6,356 0.0176 0.9824 92.88 14.5 354,346 108,234 0.3054 0.6946 91.25 15.5 230,912 23,458 0.1016 0.8984 63.38 16.5 207,454 0.0000 1.0000 56.94 17.5 168,587 0.0000 1.0000 56.94 18.5 159,386 0.0000 1.0000 56.94

19.5 34,771 0.0000 1.0000 56.94 20.5 11,313 2,800 0.2475 0.7525 56.94 21.5 8,513 2,856 0.3355 0.6645 42.85 22.5 5,656 0.0000 1.0000 28.47 23.5 5,656 0.0000 1.0000 28.47 24.5 5,656 0.0000 1.0000 28.47 25.5 2,856 0.0000 1.0000 28.47 26.5 28.47

IV-15

IV-16


ACCOUNT 473.00 SERVICES

ORIGINAL LIFE TABLE



0.0 9,419,775 471 0.0001 0.9999 100.00 0.5 10,044,906 828 0.0001 0.9999 99.99 1.5 11,120,417 3,779 0.0003 0.9997 99.98 2.5 12,212,298 4,475 0.0004 0.9996 99.95 3.5 13,125,797 6,466 0.0005 0.9995 99.91 4.5 14,044,649 7,586 0.0005 0.9995 99.86 5.5 14,505,222 10,052 0.0007 0.9993 99.81 6.5 14,991,444 8,222 0.0005 0.9995 99.74 7.5 8,504,435 1,206 0.0001 0.9999 99.69 8.5 8,613,484 1,320 0.0002 0.9998 99.68

9.5 9,432,466 1,823 0.0002 0.9998 99.66 10.5 10,095,301 2,859 0.0003 0.9997 99.64 11.5 10,894,098 4,543 0.0004 0.9996 99.61 12.5 11,605,005 6,726 0.0006 0.9994 99.57 13.5 12,269,448 8,689 0.0007 0.9993 99.51 14.5 11,574,605 8,945 0.0008 0.9992 99.44 15.5 10,768,142 8,468 0.0008 0.9992 99.36 16.5 9,701,950 7,540 0.0008 0.9992 99.28 17.5 8,828,806 7,175 0.0008 0.9992 99.20 18.5 7,931,991 6,199 0.0008 0.9992 99.12

19.5 7,290,647 6,140 0.0008 0.9992 99.04 20.5 6,716,223 6,363 0.0009 0.9991 98.96 21.5 6,250,503 7,064 0.0011 0.9989 98.87 22.5 5,843,278 7,334 0.0013 0.9987 98.76 23.5 5,142,543 7,427 0.0014 0.9986 98.63 24.5 4,635,931 7,109 0.0015 0.9985 98.49 25.5 3,979,679 6,413 0.0016 0.9984 98.34 26.5 3,266,404 5,360 0.0016 0.9984 98.18 27.5 2,598,321 4,683 0.0018 0.9982 98.02 28.5 2,227,841 3,753 0.0017 0.9983 97.84

29.5 1,765,154 3,027 0.0017 0.9983 97.67 30.5 1,487,956 2,958 0.0020 0.9980 97.50 31.5 1,269,133 2,581 0.0020 0.9980 97.31 32.5 1,000,530 2,319 0.0023 0.9977 97.12 33.5 842,417 2,226 0.0026 0.9974 96.90 34.5 676,630 2,067 0.0031 0.9969 96.65 35.5 547,365 2,075 0.0038 0.9962 96.35 36.5 422,542 2,053 0.0049 0.9951 95.98 37.5 304,491 1,737 0.0057 0.9943 95.51 38.5 147,801 604 0.0041 0.9959 94.97 39.5 94.58

IV-17

IV-18


ACCOUNT 474.00 HOUSE REG. INSTALLATIONS

ORIGINAL LIFE TABLE



0.0 1,560,413 121 0.0001 0.9999 100.00 0.5 1,640,536 360 0.0002 0.9998 99.99 1.5 1,803,308 1,197 0.0007 0.9993 99.97 2.5 1,902,362 1,621 0.0009 0.9991 99.90 3.5 2,032,760 8,726 0.0043 0.9957 99.81 4.5 2,201,606 5,183 0.0024 0.9976 99.38 5.5 2,220,274 2,898 0.0013 0.9987 99.14 6.5 2,373,488 521 0.0002 0.9998 99.01 7.5 1,357,935 447 0.0003 0.9997 98.99 8.5 1,338,352 454 0.0003 0.9997 98.96

9.5 1,441,990 450 0.0003 0.9997 98.93 10.5 1,513,633 2,698 0.0018 0.9982 98.90 11.5 1,592,983 4,338 0.0027 0.9973 98.72 12.5 1,618,427 4,097 0.0025 0.9975 98.45 13.5 1,747,684 5,516 0.0032 0.9968 98.20 14.5 1,718,423 7,911 0.0046 0.9954 97.89 15.5 1,617,776 6,308 0.0039 0.9961 97.44 16.5 1,579,104 7,507 0.0048 0.9952 97.06 17.5 1,471,731 7,875 0.0054 0.9946 96.59 18.5 1,325,981 6,493 0.0049 0.9951 96.07

19.5 1,246,147 6,795 0.0055 0.9945 95.60 20.5 1,143,254 5,501 0.0048 0.9952 95.07 21.5 1,051,509 6,505 0.0062 0.9938 94.61 22.5 981,797 3,579 0.0036 0.9964 94.02 23.5 914,938 11,000 0.0120 0.9880 93.68 24.5 876,425 10,600 0.0121 0.9879 92.56 25.5 881,434 8,914 0.0101 0.9899 91.44 26.5 845,328 9,426 0.0112 0.9888 90.52 27.5 715,281 8,587 0.0120 0.9880 89.51 28.5 614,155 9,898 0.0161 0.9839 88.44

29.5 538,440 7,419 0.0138 0.9862 87.02 30.5 466,953 9,484 0.0203 0.9797 85.82 31.5 401,668 10,128 0.0252 0.9748 84.08 32.5 331,454 6,642 0.0200 0.9800 81.96 33.5 286,621 7,124 0.0249 0.9751 80.32 34.5 231,443 8,769 0.0379 0.9621 78.32 35.5 176,195 21,630 0.1228 0.8772 75.35 36.5 128,911 1,656 0.0128 0.9872 66.10 37.5 100,483 307 0.0031 0.9969 65.25 38.5 69,827 0.0000 1.0000 65.05 39.5 65.05

IV-19

IV-20



ORIGINAL LIFE TABLE



0.0 10,025,697 30 0.0000 1.0000 100.00 0.5 11,659,776 56 0.0000 1.0000 100.00 1.5 12,543,983 51 0.0000 1.0000 100.00 2.5 12,985,533 399 0.0000 1.0000 100.00 3.5 13,133,293 2,002 0.0002 0.9998 100.00 4.5 14,539,388 792 0.0001 0.9999 99.98 5.5 14,492,641 1,074 0.0001 0.9999 99.97 6.5 15,267,506 781 0.0001 0.9999 99.96 7.5 7,411,831 764 0.0001 0.9999 99.95 8.5 8,050,068 628 0.0001 0.9999 99.94

9.5 8,069,459 459 0.0001 0.9999 99.93 10.5 8,214,260 1,058 0.0001 0.9999 99.92 11.5 8,468,804 912 0.0001 0.9999 99.91 12.5 13,493,600 593 0.0000 1.0000 99.90 13.5 13,712,475 472 0.0000 1.0000 99.90 14.5 12,202,856 3,619 0.0003 0.9997 99.90 15.5 11,144,367 3,829 0.0003 0.9997 99.87 16.5 10,541,799 1,809 0.0002 0.9998 99.84 17.5 10,163,106 459 0.0000 1.0000 99.82 18.5 8,431,883 762 0.0001 0.9999 99.82

19.5 8,299,678 109 0.0000 1.0000 99.81 20.5 7,826,465 246 0.0000 1.0000 99.81 21.5 7,697,377 219 0.0000 1.0000 99.81 22.5 6,742,933 2,810 0.0004 0.9996 99.81 23.5 6,760,942 650 0.0001 0.9999 99.77 24.5 6,698,276 1,102 0.0002 0.9998 99.76 25.5 10,533,074 384 0.0000 1.0000 99.74 26.5 5,517,445 514 0.0001 0.9999 99.74 27.5 5,297,949 5,678 0.0011 0.9989 99.73 28.5 5,093,246 7,025 0.0014 0.9986 99.62

29.5 4,846,898 1,480 0.0003 0.9997 99.48 30.5 4,840,782 254 0.0001 0.9999 99.45 31.5 4,815,053 38 0.0000 1.0000 99.44 32.5 4,788,418 155 0.0000 1.0000 99.44 33.5 4,715,938 39 0.0000 1.0000 99.44 34.5 4,353,676 1,381 0.0003 0.9997 99.44 35.5 4,317,941 3,535 0.0008 0.9992 99.41 36.5 4,198,961 570 0.0001 0.9999 99.33 37.5 4,157,751 873 0.0002 0.9998 99.32 38.5 4,074,249 1,191 0.0003 0.9997 99.30 39.5 99.27

IV-21

IV-22



ORIGINAL LIFE TABLE



0.0 9,112 0.0000 1.0000 100.00 0.5 16,074 3 0.0002 0.9998 100.00 1.5 16,070 2 0.0001 0.9999 99.98 2.5 20,323 0.0000 1.0000 99.97 3.5 89,785 12 0.0001 0.9999 99.97 4.5 86,055 6 0.0001 0.9999 99.96 5.5 92,402 0.0000 1.0000 99.95 6.5 109,434 0.0000 1.0000 99.95 7.5 104,063 0.0000 1.0000 99.95 8.5 193,580 0.0000 1.0000 99.95

9.5 245,313 0.0000 1.0000 99.95 10.5 245,313 76 0.0003 0.9997 99.95 11.5 245,237 23 0.0001 0.9999 99.92 12.5 245,214 67 0.0003 0.9997 99.91 13.5 246,041 1,314 0.0053 0.9947 99.88 14.5 247,848 346 0.0014 0.9986 99.35 15.5 259,816 166 0.0006 0.9994 99.21 16.5 255,481 565 0.0022 0.9978 99.15 17.5 211,067 120 0.0006 0.9994 98.93 18.5 215,251 3,839 0.0178 0.9822 98.87

19.5 205,265 3,394 0.0165 0.9835 97.11 20.5 185,484 492 0.0027 0.9973 95.51 21.5 184,992 0.0000 1.0000 95.25 22.5 100,090 0.0000 1.0000 95.25 23.5 51,467 85 0.0017 0.9983 95.25 24.5 51,382 1,107 0.0215 0.9785 95.09 25.5 50,275 1,684 0.0335 0.9665 93.05 26.5 48,591 187 0.0038 0.9962 89.93 27.5 47,607 3,787 0.0795 0.9205 89.59 28.5 35,074 1,178 0.0336 0.9664 82.47

29.5 23,310 78 0.0033 0.9967 79.70 30.5 23,232 0.0000 1.0000 79.44 31.5 3,461 0.0000 1.0000 79.44 32.5 79.44

IV-23

IV-24


ACCOUNT 478.00 METERS

ORIGINAL LIFE TABLE



0.0 939,335 266 0.0003 0.9997 100.00 0.5 1,124,588 2,747 0.0024 0.9976 99.97 1.5 1,371,741 3,627 0.0026 0.9974 99.73 2.5 1,598,241 2,804 0.0018 0.9982 99.47 3.5 1,930,937 1,074 0.0006 0.9994 99.29 4.5 2,300,051 1,609 0.0007 0.9993 99.23 5.5 2,385,108 4,362 0.0018 0.9982 99.16 6.5 2,482,083 5,094 0.0021 0.9979 98.98 7.5 1,918,121 2,657 0.0014 0.9986 98.77 8.5 1,981,705 4,142 0.0021 0.9979 98.63

9.5 2,174,825 5,974 0.0027 0.9973 98.42 10.5 2,294,624 7,959 0.0035 0.9965 98.15 11.5 2,382,580 9,801 0.0041 0.9959 97.81 12.5 2,512,489 10,014 0.0040 0.9960 97.41 13.5 2,719,778 10,924 0.0040 0.9960 97.02 14.5 2,677,256 10,927 0.0041 0.9959 96.63 15.5 2,567,547 13,027 0.0051 0.9949 96.23 16.5 2,412,607 17,089 0.0071 0.9929 95.74 17.5 2,168,395 15,520 0.0072 0.9928 95.06 18.5 1,904,395 10,821 0.0057 0.9943 94.38

19.5 1,850,095 11,296 0.0061 0.9939 93.84 20.5 1,803,914 14,690 0.0081 0.9919 93.27 21.5 1,758,144 18,597 0.0106 0.9894 92.51 22.5 1,647,870 18,345 0.0111 0.9889 91.53 23.5 1,499,362 14,547 0.0097 0.9903 90.51 24.5 1,394,949 14,616 0.0105 0.9895 89.63 25.5 1,473,187 18,404 0.0125 0.9875 88.69 26.5 1,330,506 21,397 0.0161 0.9839 87.58 27.5 1,117,681 18,419 0.0165 0.9835 86.17 28.5 950,697 16,359 0.0172 0.9828 84.75

29.5 813,927 13,858 0.0170 0.9830 83.29 30.5 717,532 14,280 0.0199 0.9801 81.87 31.5 610,244 12,631 0.0207 0.9793 80.24 32.5 503,888 21,832 0.0433 0.9567 78.58 33.5 416,433 18,693 0.0449 0.9551 75.18 34.5 322,264 8,010 0.0249 0.9751 71.80 35.5 260,561 4,601 0.0177 0.9823 70.01 36.5 219,250 4,101 0.0187 0.9813 68.77 37.5 176,856 8,734 0.0494 0.9506 67.48 38.5 149,993 12,614 0.0841 0.9159 64.15 39.5 58.75

IV-25

IV-26


ACCOUNT 482.00 STRUCUTRES & IMPROVEMENTS

ORIGINAL LIFE TABLE



0.0 3,494,869 199 0.0001 0.9999 100.00 0.5 3,527,134 283 0.0001 0.9999 99.99 1.5 3,464,925 1,452 0.0004 0.9996 99.98 2.5 3,401,212 5,404 0.0016 0.9984 99.94 3.5 3,187,261 2,140 0.0007 0.9993 99.78 4.5 3,029,175 3,117 0.0010 0.9990 99.71 5.5 3,009,019 203 0.0001 0.9999 99.61 6.5 3,222,928 2,128 0.0007 0.9993 99.60 7.5 749,036 3,562 0.0048 0.9952 99.53 8.5 941,476 2,496 0.0027 0.9973 99.05

9.5 989,868 9,977 0.0101 0.9899 98.78 10.5 1,013,630 9,259 0.0091 0.9909 97.78 11.5 1,081,928 9,789 0.0090 0.9910 96.89 12.5 1,368,813 8,877 0.0065 0.9935 96.02 13.5 1,370,804 9,366 0.0068 0.9932 95.40 14.5 1,155,092 5,021 0.0043 0.9957 94.75 15.5 1,150,560 17,512 0.0152 0.9848 94.34 16.5 1,130,939 12,051 0.0107 0.9893 92.91 17.5 1,103,638 2,155 0.0020 0.9980 91.92 18.5 1,188,036 992 0.0008 0.9992 91.74

19.5 1,624,042 4,765 0.0029 0.9971 91.67 20.5 1,414,148 23,011 0.0163 0.9837 91.40 21.5 1,257,054 13,059 0.0104 0.9896 89.91 22.5 1,031,280 51,356 0.0498 0.9502 88.97 23.5 933,993 37,983 0.0407 0.9593 84.54 24.5 893,620 4,159 0.0047 0.9953 81.10 25.5 926,098 2,356 0.0025 0.9975 80.72 26.5 659,464 9,836 0.0149 0.9851 80.52 27.5 640,083 4,669 0.0073 0.9927 79.32 28.5 627,668 23,641 0.0377 0.9623 78.74

29.5 603,612 11,210 0.0186 0.9814 75.77 30.5 588,741 147 0.0002 0.9998 74.36 31.5 582,926 63 0.0001 0.9999 74.35 32.5 506,738 224 0.0004 0.9996 74.34 33.5 143,028 143 0.0010 0.9990 74.31 34.5 101,957 476 0.0047 0.9953 74.24 35.5 100,983 6 0.0001 0.9999 73.89 36.5 100,909 24 0.0002 0.9998 73.88 37.5 100,186 10 0.0001 0.9999 73.87 38.5 80,634 38 0.0005 0.9995 73.86 39.5 73.82

IV-27

IV-28


ACCOUNT 484.00 TRANSPORT EQUIPMENT

ORIGINAL LIFE TABLE



0.0 3,507,858 1,121,947 0.3198 0.6802 100.00 0.5 2,723,689 177,909 0.0653 0.9347 68.02 1.5 2,332,443 109,653 0.0470 0.9530 63.58 2.5 2,473,326 232,090 0.0938 0.9062 60.59 3.5 2,293,370 314,665 0.1372 0.8628 54.91 4.5 1,638,257 196,463 0.1199 0.8801 47.38 5.5 1,566,452 38,064 0.0243 0.9757 41.70 6.5 1,533,200 54,857 0.0358 0.9642 40.69 7.5 1,171,310 59,658 0.0509 0.9491 39.23 8.5 862,306 68,346 0.0793 0.9207 37.23

9.5 836,272 72,551 0.0868 0.9132 34.28 10.5 790,091 84,117 0.1065 0.8935 31.30 11.5 706,913 45,206 0.0639 0.9361 27.97 12.5 661,706 43,764 0.0661 0.9339 26.18 13.5 617,943 24,669 0.0399 0.9601 24.45 14.5 580,787 14,538 0.0250 0.9750 23.47 15.5 515,365 7,700 0.0149 0.9851 22.88 16.5 362,757 3,403 0.0094 0.9906 22.54 17.5 333,286 973 0.0029 0.9971 22.33 18.5 235,342 85 0.0004 0.9996 22.27

19.5 172,928 0.0000 1.0000 22.26 20.5 120,180 0.0000 1.0000 22.26 21.5 72,192 0.0000 1.0000 22.26 22.5 34,811 0.0000 1.0000 22.26 23.5 13,654 0.0000 1.0000 22.26 24.5 470 0.0000 1.0000 22.26 25.5 22.26

IV-29

IV-30


ACCOUNT 485.00 HEAVY WORK EQUIPMENT

ORIGINAL LIFE TABLE



0.0 2,183,598 2,419 0.0011 0.9989 100.00 0.5 2,020,121 7,153 0.0035 0.9965 99.89 1.5 1,625,797 6,332 0.0039 0.9961 99.54 2.5 1,396,276 6,575 0.0047 0.9953 99.15 3.5 993,977 1,007 0.0010 0.9990 98.68 4.5 1,122,422 6,111 0.0054 0.9946 98.58 5.5 1,053,701 5,398 0.0051 0.9949 98.05 6.5 980,714 8,602 0.0088 0.9912 97.55 7.5 504,383 1,701 0.0034 0.9966 96.69 8.5 502,881 409 0.0008 0.9992 96.36

9.5 503,638 1,219 0.0024 0.9976 96.28 10.5 514,103 49 0.0001 0.9999 96.05 11.5 620,120 3,160 0.0051 0.9949 96.04 12.5 639,848 1,289 0.0020 0.9980 95.55 13.5 647,052 10,349 0.0160 0.9840 95.36 14.5 626,787 7,762 0.0124 0.9876 93.83 15.5 617,964 22,584 0.0365 0.9635 92.67 16.5 366,995 8,873 0.0242 0.9758 89.29 17.5 310,680 10,920 0.0351 0.9649 87.13 18.5 198,798 563 0.0028 0.9972 84.07

19.5 212,135 1,069 0.0050 0.9950 83.83 20.5 207,232 1,935 0.0093 0.9907 83.41 21.5 204,701 1,331 0.0065 0.9935 82.63 22.5 203,217 7,764 0.0382 0.9618 82.09 23.5 194,581 8,607 0.0442 0.9558 78.95 24.5 177,474 18,210 0.1026 0.8974 75.46 25.5 84,288 6,118 0.0726 0.9274 67.72 26.5 62,480 2,882 0.0461 0.9539 62.80 27.5 53,966 5,120 0.0949 0.9051 59.90 28.5 35,107 1,543 0.0440 0.9560 54.22

29.5 32,198 2,833 0.0880 0.9120 51.83 30.5 24,683 2,834 0.1148 0.8852 47.27 31.5 20,449 3,526 0.1724 0.8276 41.84 32.5 12,878 4,638 0.3601 0.6399 34.63 33.5 324 72 0.2222 0.7778 22.16 34.5 17.24

IV-31

PART V. DETAILED DEPRECIATION CALCULATIONS


ACCOUNT 443.00 GAS HOLDERS - STORAGE

CALCULATED REMAINING LIFE DEPRECIATION ACCRUAL SURVIVING AT DECEMBER 31, 2009

ORIGINAL CALCULATED ALLOC. BOOK FUT. BOOK REM. ANNUAL YEAR COST ACCRUED RESERVE ACCRUALS LIFE ACCRUAL (1) (2) (3) (4) (5) (6) (7)

SURVIVOR CURVE.. 40-SQUARE NET SALVAGE PERCENT.. 0

1997 30,000.00 9,375 7,800 22,200 27.50 807

30,000.00 9,375 7,800 22,200 807

COMPOSITE REMAINING LIFE AND ANNUAL ACCRUAL RATE, PCT.. 27.5 2.69

V-2


ACCOUNT 449.00 OTHER LOCAL STORAGE EQUIPMENT



SURVIVOR CURVE.. IOWA 33-R3 NET SALVAGE PERCENT.. 0

1997 3,200.00 1,146 1,585 1,615 21.18 76

3,200.00 1,146 1,585 1,615 76


V-3


ACCOUNT 461.00 LAND RIGHTS




1969 1,135,662.12 595,087 1,135,662 35.70 31,811 2001 35,069.99 3,966 35,070 66.52 527

1,170,732.11 599,053 1,170,732 32,338


V-4






1969 32,444.36 31,211 32,444 1970 771.30 736 771 1971 229.57 217 230 1972 169.94 159 170 1973 883.16 820 883 1974 61.55 57 61 1 2.44 1975 259.54 236 255 5 2.73 2 1976 220.52 198 214 7 3.04 2 1979 1,161.44 1,000 1,079 82 4.16 20 1980 107.05 91 98 9 4.63 2 1982 791,038.72 640,188 690,678 100,361 5.72 17,546 1983 41,255.48 32,538 35,104 6,151 6.34 970 1984 74,075.54 56,794 61,273 12,803 7.00 1,829 1985 37,683.63 28,037 30,248 7,436 7.68 968 1986 191,860.16 138,197 149,096 42,764 8.39 5,097 1987 33,107.84 23,043 24,860 8,248 9.12 904 1988 91,800.91 61,598 66,456 25,345 9.87 2,568 1989 89,598.56 57,791 62,349 27,250 10.65 2,559 1990 24,048.61 14,862 16,034 8,015 11.46 699 1991 42,289.78 24,964 26,933 15,357 12.29 1,250 1992 10,356.79 5,821 6,280 4,077 13.14 310 1993 36,060.36 19,220 20,736 15,324 14.01 1,094 1994 70,339.52 35,381 38,172 32,168 14.91 2,157 2000 128,074.44 40,254 43,429 84,645 20.57 4,115 2001 383,257.42 107,964 116,479 266,778 21.55 12,379 2003 5,387.92 1,162 1,254 4,134 23.53 176 2004 10,778.31 1,969 2,124 8,654 24.52 353 2005 7,700.00 1,153 1,244 6,456 25.51 253 2006 173,310.24 20,156 21,745 151,565 26.51 5,717 2007 15,288.00 1,273 1,374 13,914 27.50 506 2008 4,901.11 245 264 4,637 28.50 163 2009 6,000.00 100 108 5,892 29.50 200

2,304,521.77 1,347,435 1,452,445 852,078 61,839


V-5






1969 44,569.52 40,812 44,570 1970 16,321.18 14,803 16,321 1971 7,491.90 6,728 7,454 38 3.06 12 1972 7,914.17 7,036 7,796 118 3.33 35 1973 7,754.43 6,818 7,554 200 3.62 55 1974 3,721.35 3,235 3,584 137 3.92 35 1975 5,396.22 4,632 5,132 264 4.25 62 1976 2,941.70 2,491 2,760 182 4.60 40 1977 1,523.08 1,270 1,407 116 4.98 23 1978 276.56 227 252 25 5.38 5 1979 1,756.31 1,416 1,569 187 5.82 32 1980 4,573.65 3,615 4,005 569 6.29 90 1981 8,006.50 6,195 6,864 1,143 6.79 168 1982 238,583.62 180,298 199,767 38,817 7.33 5,296 1983 19,304.54 14,227 15,763 3,542 7.89 449 1984 49,267.74 35,340 39,156 10,112 8.48 1,192 1985 37,739.19 26,293 29,132 8,607 9.10 946 1986 6,189.06 4,178 4,629 1,560 9.75 160 1987 23,752.78 15,494 17,167 6,586 10.43 631 1988 222,424.48 139,972 155,086 67,338 11.12 6,056 1989 4,992.16 3,022 3,348 1,644 11.84 139 1990 21,964.23 12,755 14,132 7,832 12.58 623 1991 31,134.98 17,289 19,156 11,979 13.34 898 1992 152,049.63 80,480 89,171 62,879 14.12 4,453 1993 52,143.28 26,228 29,060 23,083 14.91 1,548 1994 150,914.51 71,835 79,592 71,323 15.72 4,537 2000 20,873.62 6,310 6,991 13,883 20.93 663 2001 8,331.17 2,264 2,508 5,823 21.85 266 2003 33,067.63 6,934 7,683 25,385 23.71 1,071 2004 8,838.20 1,573 1,743 7,095 24.66 288 2005 11,912.06 1,739 1,927 9,985 25.62 390 2006 48,586.77 5,539 6,137 42,450 26.58 1,597 2007 25,410.35 2,076 2,300 23,110 27.55 839 2008 4,650.00 228 253 4,397 28.53 154

1,284,376.57 753,352 833,969 450,409 32,753


V-6






1969 17,726,273.38 10,621,583 15,793,451 1,932,822 24.05 80,367 1970 359,608.97 211,019 313,769 45,840 24.79 1,849 1971 176,868.19 101,611 151,087 25,781 25.53 1,010 1972 502,425.91 282,263 419,703 82,723 26.29 3,147 1973 149,511.51 82,082 122,049 27,463 27.06 1,015 1974 1,576,424.25 844,963 1,256,393 320,031 27.84 11,495 1975 314,764.47 164,559 244,686 70,078 28.63 2,448 1976 115,753.76 59,000 87,728 28,026 29.42 953 1977 110,869.25 55,013 81,800 29,069 30.23 962 1978 20,180.11 9,741 14,484 5,696 31.04 184 1979 1,041,555.76 488,490 726,346 315,210 31.86 9,894 1980 866,174.01 394,282 586,266 279,908 32.69 8,562 1981 953,026.13 420,475 625,213 327,813 33.53 9,777 1982 21,826,749.67 9,320,022 13,858,133 7,968,617 34.38 231,781 1983 1,126,127.86 464,866 691,219 434,909 35.23 12,345 1984 631,035.17 251,468 373,913 257,122 36.09 7,124 1985 86,977.78 33,399 49,662 37,316 36.96 1,010 1986 4,657,199.83 1,719,904 2,557,361 2,099,839 37.84 55,493 1987 710,778.72 252,113 374,872 335,907 38.72 8,675 1988 3,640,740.53 1,237,124 1,839,505 1,801,236 39.61 45,474 1989 887,823.35 288,365 428,776 459,047 40.51 11,332 1990 7,648,529.12 2,369,514 3,523,279 4,125,250 41.41 99,620 1991 1,751,410.94 516,141 767,461 983,950 42.32 23,250 1992 2,625,995.77 733,441 1,090,569 1,535,427 43.24 35,509 1993 5,635,040.97 1,487,651 2,212,019 3,423,022 44.16 77,514 1994 6,025,272.01 1,498,485 2,228,128 3,797,144 45.08 84,231 1996 274,928.08 59,742 88,832 186,096 46.96 3,963 2000 6,024,782.68 929,021 1,381,380 4,643,403 50.75 91,496 2001 28,626,131.31 3,956,131 5,882,453 22,743,678 51.71 439,831 2002 2,185,623.41 266,646 396,481 1,789,142 52.68 33,962 2003 1,339,818.22 141,753 210,775 1,129,043 53.65 21,045 2004 1,239,830.34 111,213 165,365 1,074,465 54.62 19,672 2005 6,748,669.44 496,027 737,553 6,011,116 55.59 108,133 2006 4,197,292.22 240,505 357,612 3,839,680 56.56 67,887 2007 3,833,705.25 157,182 233,717 3,599,988 57.54 62,565 2008 4,850,373.18 119,804 178,139 4,672,234 58.52 79,840 2009 2,609,157.89 21,395 31,813 2,577,345 59.51 43,309

143,097,429.44 40,406,993 60,081,992 83,015,436 1,796,724


V-7





SURVIVOR CURVE.. IOWA 30-R2.5 NET SALVAGE PERCENT.. 0

1969 307,953.61 269,767 307,954 1970 7,320.94 6,355 7,321 1971 2,178.98 1,872 2,179 1972 1,613.07 1,372 1,613 1973 8,382.72 7,050 8,383 1974 584.19 485 583 1 5.07 1975 2,463.46 2,021 2,428 35 5.39 6 1976 2,093.09 1,693 2,034 59 5.74 10 1979 11,024.06 8,474 10,180 844 6.94 122 1980 1,016.09 765 919 97 7.40 13 1982 7,508,337.86 5,403,751 6,491,887 1,016,451 8.41 120,862 1983 391,586.48 274,776 330,107 61,479 8.95 6,869 1984 703,106.14 480,011 576,669 126,437 9.52 13,281 1985 357,683.40 237,037 284,768 72,915 10.12 7,205 1986 1,821,087.74 1,169,138 1,404,564 416,524 10.74 38,782 1987 314,251.16 195,056 234,334 79,917 11.38 7,023 1988 871,350.80 521,329 626,307 245,044 12.05 20,336 1989 850,446.70 489,602 588,192 262,255 12.73 20,601 1990 228,263.25 126,070 151,456 76,807 13.43 5,719 1991 401,403.78 211,941 254,619 146,785 14.16 10,366 1992 98,304.00 49,476 59,439 38,865 14.90 2,608 1993 342,275.79 163,711 196,677 145,599 15.65 9,303 1994 635,075.37 287,499 345,392 289,683 16.42 17,642 2000 331,832.97 95,568 114,812 217,021 21.36 10,160 2001 3,102,044.61 803,430 965,214 2,136,831 22.23 96,124 2002 440,023.54 101,073 121,426 318,598 23.11 13,786 2003 606,535.01 121,307 145,734 460,801 24.00 19,200 2004 559,181.83 95,061 114,203 444,979 24.90 17,871 2005 105,788.44 14,779 17,755 88,033 25.81 3,411 2006 92,110.51 10,040 12,062 80,049 26.73 2,995 2007 66,472.17 5,205 6,253 60,219 27.65 2,178 2008 12,824.62 603 724 12,101 28.59 423 2009 30,616.00 481 578 30,038 29.53 1,017

20,215,232.38 11,156,798 13,386,766 6,828,467 447,913


V-8






1969 146,299.34 136,995 146,299 1970 53,574.23 49,545 53,574 1971 24,592.14 22,458 24,592 1972 25,978.26 23,422 25,978 1973 25,453.91 22,654 25,454 1974 12,215.32 10,725 12,215 1975 17,713.07 15,340 17,713 1976 9,656.12 8,246 9,656 1977 4,999.52 4,206 5,000 1978 907.82 752 903 5 4.30 1 1979 5,765.08 4,693 5,637 128 4.65 28 1980 15,012.99 12,004 14,419 594 5.01 119 1981 26,281.32 20,615 24,763 1,518 5.39 282 1982 783,150.16 601,459 722,468 60,682 5.80 10,462 1983 63,367.11 47,576 57,148 6,219 6.23 998 1984 161,721.23 118,509 142,352 19,369 6.68 2,900 1985 123,878.82 88,400 106,185 17,694 7.16 2,471 1986 20,315.57 14,091 16,926 3,390 7.66 443 1987 77,968.45 52,457 63,011 14,957 8.18 1,828 1988 730,107.84 475,154 570,751 159,357 8.73 18,254 1989 16,386.74 10,291 12,361 4,026 9.30 433 1990 72,097.54 43,576 52,343 19,755 9.89 1,997 1991 102,200.49 59,276 71,202 30,998 10.50 2,952 1992 499,102.55 276,702 332,372 166,731 11.14 14,967 1993 171,160.18 90,373 108,555 62,605 11.80 5,306 1994 501,896.74 251,551 302,161 199,736 12.47 16,017 2000 257,462.18 83,315 100,077 157,385 16.91 9,307 2001 1,708,669.57 498,932 599,314 1,109,356 17.70 62,675 2002 20,810.89 5,403 6,490 14,321 18.51 774 2003 126,622.64 28,667 34,435 92,188 19.34 4,767 2004 443,371.01 85,482 102,680 340,691 20.18 16,883 2005 167,927.88 26,667 32,032 135,896 21.03 6,462 2006 101,219.92 12,592 15,125 86,095 21.89 3,933 2007 275,685.13 24,701 29,671 246,014 22.76 10,809 2008 57,558.56 3,108 3,733 53,826 23.65 2,276 2009 705,327.46 12,696 15,251 690,076 24.55 28,109

7,556,457.78 3,242,633 3,862,846 3,693,612 225,453


V-9


ACCOUNT 468.00 COMMUNICATIONS STRUCTURES & EQUIPMENT




1978 5,872.28 5,872 5,872 1980 31,634.23 31,634 31,634 1981 272.41 272 272 1982 2,794.94 2,778 2,795 1983 1,939.57 1,894 1,940 1984 10,792.03 10,346 10,792 1985 22,619.23 21,262 22,619 1987 115,073.84 103,716 115,074 1988 4,488.43 3,959 4,488 1989 59,689.88 51,453 59,690 1990 141,260.74 118,843 141,261 1991 171,915.20 140,747 171,915 1992 28,624.08 22,748 28,624 1994 44,833.35 33,118 44,833 2000 126,844.58 64,691 113,187 13,658 7.35 1,858 2001 1,374,253.44 637,654 1,115,673 258,580 8.04 32,162 2002 82,649.82 34,324 60,055 22,595 8.77 2,576 2003 1,327.63 485 849 479 9.52 50 2004 100,724.08 31,557 55,214 45,510 10.30 4,418 2005 82,252.17 21,328 37,316 44,936 11.11 4,045 2006 552,683.45 112,747 197,268 355,415 11.94 29,767 2007 4,179.42 616 1,078 3,101 12.79 242 2008 1,801.96 161 282 1,520 13.66 111 2009 2,052.85 62 108 1,945 14.55 134

2,970,579.61 1,452,267 2,222,839 747,739 75,363


V-10


ACCOUNT 469.00 OTHER




2001 1,943.15 413 934 1,009 31.50 32

1,943.15 413 934 1,009 32


V-11






1969 34,278.49 17,962 34,278 35.70 960

34,278.49 17,962 34,278 960


V-12






1982 2,856.44 2,159 1,498 1,358 7.33 185 1983 2,800.01 2,064 1,432 1,368 7.89 173 1988 23,457.89 14,762 10,245 13,213 11.12 1,188 1989 124,614.94 75,429 52,348 72,267 11.84 6,104 1990 9,201.34 5,343 3,708 5,493 12.58 437 1991 38,866.65 21,583 14,978 23,889 13.34 1,791 1993 15,199.69 7,645 5,306 9,894 14.91 664 2001 184.05 50 35 149 21.85 7 2002 3,168.10 763 529 2,639 22.78 116 2009 6,081.94 99 69 6,013 29.51 204

226,431.05 129,897 90,148 136,283 10,869


V-13






1969 147,197.33 96,944 147,197 1970 154,953.65 100,131 154,954 1971 115,997.41 73,496 115,997 1972 122,747.73 76,177 122,748 1973 127,198.10 77,260 127,198 1974 163,560.85 97,155 161,352 2,209 20.30 109 1975 155,793.38 90,391 150,119 5,674 20.99 270 1976 266,021.39 150,675 250,237 15,784 21.68 728 1977 215,865.39 119,201 197,966 17,899 22.39 799 1978 274,171.56 147,449 244,879 29,293 23.11 1,268 1979 458,933.64 240,114 398,775 60,159 23.84 2,523 1980 365,797.41 185,971 308,855 56,942 24.58 2,317 1981 662,722.39 326,987 543,051 119,671 25.33 4,724 1982 706,861.90 338,021 561,376 145,486 26.09 5,576 1983 799,586.63 370,049 614,567 185,020 26.86 6,888 1984 657,392.36 294,117 488,461 168,931 27.63 6,114 1985 811,723.65 350,340 581,835 229,889 28.42 8,089 1986 525,264.59 218,300 362,546 162,719 29.22 5,569 1987 588,887.79 235,320 390,813 198,075 30.02 6,598 1988 734,710.35 281,541 467,575 267,135 30.84 8,662 1989 793,549.71 291,074 483,407 310,143 31.66 9,796 1990 1,159,922.10 406,205 674,614 485,308 32.49 14,937 1991 1,084,774.03 361,664 600,641 484,133 33.33 14,525 1992 1,335,899.57 422,679 701,973 633,927 34.18 18,547 1993 1,262,858.24 378,100 627,938 634,920 35.03 18,125 1994 1,056,822.64 298,235 495,300 561,523 35.89 15,646 1997 7,200.00 1,653 2,745 4,455 38.52 116 2000 420,298.81 73,973 122,852 297,447 41.20 7,220 2001 7,073,333.57 1,116,172 1,853,707 5,219,627 42.11 123,952 2002 245,167.07 34,225 56,840 188,327 43.02 4,378 2003 332,328.82 40,345 67,004 265,325 43.93 6,040 2004 244,273.51 25,111 41,704 202,570 44.86 4,516 2005 175,414.93 14,805 24,588 150,827 45.78 3,295 2006 250,351.12 16,473 27,358 222,993 46.71 4,774 2007 195,638.35 9,195 15,270 180,368 47.65 3,785 2008 438,494.71 12,366 20,537 417,958 48.59 8,602 2009 169,951.72 1,598 2,654 167,298 49.53 3,378

24,301,666.40 7,373,512 12,209,633 12,092,035 321,866


V-14






1969 69,827.08 59,842 61,696 8,131 4.29 1,895 1970 30,347.97 25,696 26,492 3,856 4.60 838 1971 26,772.10 22,381 23,075 3,697 4.92 751 1972 25,654.29 21,157 21,813 3,841 5.26 730 1973 46,478.81 37,787 38,958 7,521 5.61 1,341 1974 48,053.69 38,491 39,684 8,370 5.97 1,402 1975 38,191.42 30,095 31,028 7,163 6.36 1,126 1976 60,085.89 46,567 48,010 12,076 6.75 1,789 1977 55,800.47 42,464 43,780 12,020 7.17 1,676 1978 64,068.15 47,814 49,296 14,772 7.61 1,941 1979 65,816.67 48,132 49,624 16,193 8.06 2,009 1980 92,539.02 66,193 68,244 24,295 8.54 2,845 1981 120,621.34 84,314 86,927 33,694 9.03 3,731 1982 27,191.63 18,537 19,111 8,081 9.55 846 1983 77,584.19 51,493 53,089 24,495 10.09 2,428 1984 66,911.01 43,178 44,516 22,395 10.64 2,105 1985 97,303.10 60,941 62,829 34,474 11.21 3,075 1986 95,199.81 57,720 59,509 35,691 11.81 3,022 1987 143,230.04 83,933 86,534 56,696 12.42 4,565 1988 154,096.56 87,065 89,763 64,334 13.05 4,930 1989 118,754.57 64,567 66,568 52,187 13.69 3,812 1990 208,324.02 108,599 111,964 96,360 14.36 6,710 1991 164,426.22 81,999 84,540 79,886 15.04 5,312 1992 105,565.14 50,217 51,773 53,792 15.73 3,420 1993 167,056.98 75,510 77,850 89,207 16.44 5,426 1994 127,097.75 54,360 56,045 71,053 17.17 4,138 1997 2,200.00 775 799 1,401 19.43 72 2000 120,326.21 32,849 33,867 86,459 21.81 3,964 2001 1,166,393.35 286,583 295,464 870,929 22.63 38,486 2002 5,871.73 1,280 1,320 4,552 23.46 194 2003 100,398.23 19,076 19,667 80,731 24.30 3,322 2004 39,465.41 6,382 6,580 32,885 25.15 1,308 2005 38,623.73 5,137 5,296 33,328 26.01 1,281 2006 8,928.40 929 958 7,970 26.88 297 2007 9,106.01 680 701 8,405 27.76 303 2008 50,428.37 2,269 2,339 48,089 28.65 1,678 2009 41,942.00 629 648 41,294 29.55 1,397

3,880,681.36 1,765,641 1,820,357 2,060,323 124,165


V-15






1969 4,073,057.50 2,440,576 3,420,645 652,413 24.05 27,127 1970 82,629.21 48,487 67,958 14,671 24.79 592 1971 40,639.92 23,348 32,724 7,916 25.53 310 1972 115,445.00 64,857 90,902 24,543 26.29 934 1973 34,354.03 18,860 26,434 7,920 27.06 293 1974 362,223.15 194,152 272,118 90,105 27.84 3,237 1975 72,325.06 37,812 52,996 19,329 28.63 675 1976 26,597.34 13,557 19,001 7,596 29.42 258 1977 25,475.00 12,641 17,717 7,758 30.23 257 1978 4,636.89 2,238 3,137 1,500 31.04 48 1979 239,323.65 112,243 157,317 82,007 31.86 2,574 1980 199,025.28 90,596 126,977 72,048 32.69 2,204 1981 218,981.74 96,615 135,413 83,569 33.53 2,492 1982 5,015,245.14 2,141,510 3,001,482 2,013,763 34.38 58,574 1983 258,756.22 106,815 149,709 109,047 35.23 3,095 1984 144,996.21 57,781 80,984 64,012 36.09 1,774 1985 19,985.33 7,674 10,756 9,229 36.96 250 1986 1,070,108.89 395,191 553,889 516,220 37.84 13,642 1987 163,319.30 57,929 81,192 82,127 38.72 2,121 1988 836,551.78 284,260 398,411 438,141 39.61 11,061 1989 203,999.76 66,259 92,867 111,133 40.51 2,743 1990 1,757,442.09 544,456 763,095 994,347 41.41 24,012 1991 402,430.75 118,596 166,221 236,210 42.32 5,582 1992 603,388.63 168,526 236,201 367,188 43.24 8,492 1993 1,294,792.50 341,825 479,093 815,700 44.16 18,471 1994 1,708,642.88 424,939 595,583 1,113,060 45.08 24,691 1997 3,659.96 738 1,034 2,626 47.90 55 2000 432,823.53 66,741 93,542 339,282 50.75 6,685 2001 8,018,459.72 1,108,151 1,553,155 6,465,305 51.71 125,030 2002 61,786.77 7,538 10,565 51,222 52.68 972 2003 250,221.05 26,473 37,104 213,117 53.65 3,972 2004 351,498.98 31,529 44,190 307,309 54.62 5,626 2005 254,729.77 18,723 26,242 228,488 55.59 4,110 2006 162,432.64 9,307 13,044 149,389 56.56 2,641 2007 411,809.79 16,884 23,664 388,146 57.54 6,746 2008 76,111.42 1,880 2,635 73,476 58.52 1,256 2009 367,122.80 3,010 4,219 362,904 59.51 6,098

29,365,029.68 9,162,717 12,842,216 16,522,816 378,700


V-16






1976 3,460.55 3,445 2,299 1,162 0.09 1,162 1977 19,771.22 19,465 12,990 6,781 0.31 6,781 1979 10,585.56 10,167 6,785 3,801 0.79 3,801 1980 8,746.47 8,292 5,534 3,212 1.04 3,088 1981 797.01 745 497 300 1.30 231 1985 48,623.20 42,886 28,621 20,002 2.36 8,475 1986 84,901.16 73,567 49,097 35,804 2.67 13,410 1988 16,387.13 13,618 9,088 7,299 3.38 2,159 1989 6,146.65 4,976 3,321 2,826 3.81 742 1991 67,820.93 51,578 34,423 33,398 4.79 6,972 1992 4,169.33 3,052 2,037 2,132 5.36 398 1994 6,862.28 4,594 3,066 3,796 6.61 574 2001 5,370.51 2,140 1,428 3,943 12.03 328 2004 3,717.98 982 655 3,063 14.72 208

287,359.98 239,507 159,841 127,519 48,329


V-17






1969 137,379.13 128,642 95,457 41,922 1.59 26,366 1970 18,128.58 16,765 12,440 5,689 1.88 3,026 1971 38,292.38 34,969 25,948 12,344 2.17 5,688 1972 36,711.09 33,099 24,561 12,150 2.46 4,939 1973 53,692.62 47,786 35,459 18,234 2.75 6,631 1974 75,476.17 66,268 49,174 26,302 3.05 8,624 1975 65,622.65 56,829 42,169 23,454 3.35 7,001 1976 93,725.74 80,042 59,394 34,332 3.65 9,406 1977 93,007.31 78,238 58,056 34,951 3.97 8,804 1978 82,537.59 68,341 50,712 31,826 4.30 7,401 1979 120,410.73 98,014 72,730 47,681 4.65 10,254 1980 148,564.47 118,792 88,148 60,416 5.01 12,059 1981 191,428.15 150,156 111,422 80,006 5.39 14,843 1982 124,276.74 95,445 70,824 53,453 5.80 9,216 1983 92,194.16 69,219 51,363 40,831 6.23 6,554 1984 113,844.53 83,425 61,905 51,940 6.68 7,775 1985 179,955.82 128,416 95,290 84,666 7.16 11,825 1986 138,631.22 96,155 71,351 67,280 7.66 8,783 1987 98,667.51 66,384 49,260 49,408 8.18 6,040 1988 128,441.93 83,590 62,027 66,415 8.73 7,608 1989 123,635.22 77,643 57,614 66,021 9.30 7,099 1990 361,365.38 218,409 162,068 199,297 9.89 20,151 1991 337,663.83 195,845 145,325 192,339 10.50 18,318 1992 238,785.29 132,383 98,233 140,552 11.14 12,617 1993 238,441.09 125,897 93,421 145,020 11.80 12,290 1994 202,000.95 101,243 75,126 126,875 12.47 10,174 1997 6,800.00 2,826 2,097 4,703 14.61 322 2000 84,630.50 27,386 20,322 64,309 16.91 3,803 2001 665,531.56 194,335 144,204 521,328 17.70 29,454 2002 36,651.25 9,515 7,061 29,590 18.51 1,599 2003 45,398.50 10,278 7,627 37,772 19.34 1,953 2004 13,779.58 2,657 1,971 11,809 20.18 585 2005 21,515.20 3,417 2,536 18,979 21.03 902 2006 21,194.20 2,637 1,957 19,237 21.89 879 2008 25,371.35 1,370 1,016 24,355 23.65 1,030

4,453,752.42 2,706,416 2,008,268 2,445,486 304,019


V-18


ACCOUNT 479.00 OTHER DIST. EQUIPMENTS




1997 5,300.00 1,893 31,457- 36,757 22.50 1,634 2001 25,214.62 6,125 101,784- 126,999 26.50 4,792

30,514.62 8,018 133,241- 163,756 6,426


V-19






1969 350.00 183 350 35.70 10

350.00 183 350 10


V-20






1969 80,596.49 75,471 80,596 1970 19,541.53 18,072 19,542 1971 698.76 638 692 7 2.17 3 1972 68.61 62 67 2 2.46 1 1973 498.16 443 481 17 2.75 6 1974 40,928.03 35,935 39,000 1,928 3.05 632 1975 363,486.24 314,779 341,623 21,863 3.35 6,526 1976 76,124.25 65,010 70,554 5,570 3.65 1,526 1977 5,668.41 4,768 5,175 493 3.97 124 1978 3,660.12 3,031 3,289 371 4.30 86 1979 415.38 338 367 48 4.65 10 1980 7,746.06 6,194 6,722 1,024 5.01 204 1981 9,544.80 7,487 8,125 1,420 5.39 263 1982 264,278.17 202,966 220,275 44,003 5.80 7,587 1983 83,960.55 63,038 68,414 15,547 6.23 2,496 1984 30,791.10 22,564 24,488 6,303 6.68 944 1985 46,918.60 33,481 36,336 10,583 7.16 1,478 1986 212,809.78 147,605 160,193 52,617 7.66 6,869 1987 134,752.55 90,662 98,394 36,359 8.18 4,445 1988 258,758.16 168,400 182,761 75,997 8.73 8,705 1989 27,969.20 17,565 19,063 8,906 9.30 958 1990 8,615.60 5,207 5,651 2,965 9.89 300 1991 22,183.70 12,867 13,964 8,220 10.50 783 1992 6,496.94 3,602 3,909 2,588 11.14 232 1994 215,304.47 107,911 117,114 98,190 12.47 7,874 1997 15,500.00 6,442 6,991 8,509 14.61 582 2000 32,710.54 10,585 11,488 21,223 16.91 1,255 2001 2,615,408.49 763,699 828,826 1,786,582 17.70 100,937 2002 59,730.96 15,506 16,828 42,903 18.51 2,318 2003 46,445.99 10,515 11,412 35,034 19.34 1,811 2004 164,952.01 31,803 34,515 130,437 20.18 6,464 2005 231,617.52 36,781 39,918 191,700 21.03 9,116 2006 68,985.72 8,582 9,314 59,672 21.89 2,726 2007 61,926.74 5,549 6,022 55,905 22.76 2,456 2008 188,684.66 10,189 11,058 177,627 23.65 7,511 2009 241,264.59 4,343 4,713 236,552 24.55 9,636

5,649,042.88 2,312,090 2,507,880 3,141,165 196,864


V-21


ACCOUNT 483.00 OFFICE FURNITURE / EQUIPMENT




1969 417,293.85 417,294 417,294 1997 200.00 167 250- 450 2.50 180 2000 15,506.02 9,820 14,712- 30,218 5.50 5,494 2001 110,001.29 62,338 93,391- 203,392 6.50 31,291 2002 37,870.51 18,935 28,367- 66,238 7.50 8,832 2003 51,640.02 22,376 33,522- 85,162 8.50 10,019 2004 39,259.16 14,396 21,567- 60,826 9.50 6,403 2005 48,899.29 14,670 21,978- 70,877 10.50 6,750 2008 36,797.92 3,680 5,513- 42,311 13.50 3,134 2009 58,312.91 1,942 2,909- 61,222 14.50 4,222

815,780.97 565,618 195,085 620,696 76,325


V-22





SURVIVOR CURVE.. IOWA 7-L1.5 NET SALVAGE PERCENT.. +20

1983 469.51 376 376 1984 13,184.84 10,548 10,548 1985 21,156.23 16,925 16,925 1986 37,381.45 29,905 29,905 1987 47,988.03 38,390 38,390 1988 52,747.49 40,991 10,532- 52,730 0.20 52,730 1989 62,329.28 47,440 12,189- 62,052 0.34 62,052 1990 96,971.28 72,038 18,510- 96,087 0.50 96,087 1991 26,067.27 18,916 4,860- 25,714 0.65 25,714 1992 144,908.29 102,676 26,382- 142,309 0.80 142,309 1993 50,884.57 35,184 9,040- 49,748 0.95 49,748 1994 12,486.16 8,405 2,160- 12,149 1.11 10,945 2000 324,108.73 172,244 44,257- 303,544 2.35 129,168 2001 403,009.05 202,182 51,950- 374,357 2.61 143,432 2002 100,683.70 47,523 12,211- 92,758 2.87 32,320 2004 534,390.87 217,433 55,868- 483,381 3.44 140,518 2006 39,280.42 12,347 3,172- 34,596 4.25 8,140 2007 315,106.43 76,710 19,710- 271,795 4.87 55,810 2008 37,349.99 5,848 1,503- 31,383 5.63 5,574 2009 72,491.68 3,978 1,022- 59,015 6.52 9,051

2,392,995.27 1,160,059 177,222- 2,091,618 963,598


V-23





SURVIVOR CURVE.. IOWA 15-R2 NET SALVAGE PERCENT.. +15

1974 252.83 215 215 1975 7,916.09 6,729 6,729 1976 4,044.40 3,438 3,438 1977 1,400.36 1,190 1,190 1978 4,681.82 3,980 3,980 1979 1,366.53 1,162 1,162 1980 13,738.32 11,678 11,678 1981 5,631.71 4,787 4,787 1982 15,689.74 13,256 13,336 1983 74,975.85 62,245 63,729 1984 8,500.09 6,927 7,225 1985 871.55 696 741 1986 153.12 120 130 1987 596.47 457 507 1988 4,339.07 3,253 3,688 1989 1,931.84 1,415 1,617 25 2.07 12 1990 109,051.00 77,983 89,095 3,598 2.38 1,512 1991 50,034.64 34,819 39,780 2,749 2.72 1,011 1992 236,478.51 159,740 182,501 18,506 3.08 6,008 1993 3,300.15 2,154 2,461 344 3.48 99 1994 31,441.84 19,742 22,555 4,171 3.92 1,064 2001 468,485.89 184,771 211,098 187,115 8.04 23,273 2002 72,968.46 25,758 29,428 32,595 8.77 3,717 2003 64,950.42 20,167 23,041 32,167 9.52 3,379 2005 453,995.15 100,063 114,320 271,576 11.11 24,444 2006 493,870.24 85,637 97,839 321,951 11.94 26,964 2007 390,889.18 48,941 55,914 276,342 12.79 21,606 2008 195,995.58 14,877 16,997 149,599 13.66 10,952 2009 278,744.06 7,108 8,121 228,811 14.55 15,726

2,996,294.91 903,308 1,017,302 1,529,549 139,767


V-24


ACCOUNT 486.00 TOOLS / WORK EQUIPMENT




1969 40,782.07 40,782 40,782 1970 5,824.57 5,825 5,825 1971 8,836.21 8,836 8,836 1972 3,858.63 3,859 3,859 1973 5,998.55 5,999 5,999 1974 3,223.15 3,223 3,223 1975 12,442.11 12,442 12,442 1976 5,458.30 5,458 5,458 1977 3,917.23 3,917 3,917 1978 4,534.39 4,534 4,534 1979 12,978.69 12,979 12,979 1980 21,982.47 21,982 21,982 1981 46,681.72 46,682 46,682 1982 79,546.92 79,547 79,547 1983 74,079.46 74,079 74,079 1984 54,921.83 54,922 54,922 1985 82,230.74 82,231 82,231 1986 44,707.54 44,708 44,708 1987 88,512.23 88,512 88,512 1988 92,932.17 92,932 92,932 1989 77,200.97 77,201 77,201 1990 124,967.76 121,844 31,361- 156,329 0.50 156,329 1991 66,628.66 61,632 15,863- 82,492 1.50 54,995 1992 55,804.53 48,829 12,568- 68,373 2.50 27,349 1993 39,318.83 32,438 8,349- 47,668 3.50 13,619 1994 33,267.68 25,782 6,636- 39,904 4.50 8,868 2000 212,575.21 100,973 25,989- 238,564 10.50 22,720 2001 322,633.36 137,119 35,292- 357,925 11.50 31,124 2002 198,187.08 74,320 19,128- 217,315 12.50 17,385 2003 102,147.62 33,198 8,545- 110,693 13.50 8,199 2004 140,045.90 38,513 9,912- 149,958 14.50 10,342 2005 105,882.37 23,824 6,132- 112,014 15.50 7,227 2007 168,486.61 21,061 5,421- 173,908 17.50 9,938 2008 108,699.76 8,152 2,098- 110,798 18.50 5,989 2009 87,798.02 2,195 565- 88,363 19.50 4,531

2,537,093.34 1,500,530 582,791 1,954,304 378,615


V-25


ACCOUNT 487.00 COMPUTER EQUIPMENT




1984 52,179.73 52,180 52,180 1985 7,456.47 7,456 7,456 1986 16,239.74 16,240 16,240 1987 23,372.27 23,372 23,372 1988 20,629.90 20,630 20,630 1989 80,124.84 80,125 80,125 1990 81,382.87 81,383 81,383 1991 99,240.07 99,240 99,240 1992 11,819.26 11,819 11,819 1993 75,114.91 75,115 75,115 1994 66,888.44 66,888 66,888 2000 281,502.90 281,503 281,503 2001 171,315.80 171,316 171,316 2002 177,775.85 177,776 177,776 2003 89,474.65 89,475 89,475 2004 74,742.76 74,743 74,743 2006 18,693.49 13,085 145,584- 164,277 1.50 109,518 2007 91,994.92 45,997 511,765- 603,760 2.50 241,504 2008 133.16 40 445- 578 3.50 165 2009 13,610.00 1,361 15,143- 28,753 4.50 6,390

1,453,692.03 1,389,744 656,324 797,368 357,577


V-26


ACCOUNT 488.00 COMMUNICATION STRUCTURES & EQUIP.




1980 9.46 9 9 1981 4,827.47 4,827 4,827 1982 16,755.23 16,755 16,755 1983 8,875.59 8,876 8,876 1984 2,632.22 2,632 2,632 1985 702.75 703 703 1986 1,214.43 1,214 1,214 1987 22,368.68 22,369 22,369 1988 5,581.29 5,581 5,581 1989 7,919.36 7,919 7,919 1990 20,413.66 20,414 20,414 1991 25,016.03 25,016 25,016 1992 19,781.85 19,782 19,782 1993 9,111.98 9,112 9,112 1994 3,783.29 3,783 3,783 2000 105,510.31 71,599 67,228 38,282 4.50 8,507 2001 326,543.97 198,245 186,144 140,400 5.50 25,527 2002 25,340.73 13,575 12,746 12,595 6.50 1,938 2003 8,167.78 3,792 3,560 4,608 7.50 614 2004 7,188.65 2,824 2,652 4,537 8.50 534 2005 13,612.06 4,375 4,108 9,504 9.50 1,000

635,356.79 443,402 425,430 209,926 38,120


V-27


ACCOUNT 489.00 GENERAL EQUIPMENT




1997 2,000.00 1,250 535 1,465 7.50 195

2,000.00 1,250 535 1,465 195


V-28

PACIFIC NORTHERN GAS (N.E.) LTD. DAWSON CREEK





1990 10,967.40 2,837 10,967 55.60 197

10,967.40 2,837 10,967 197


V-29






1970 3,568.45 3,237 2,908 660 2.79 237 1990 912.88 530 476 437 12.58 35 2003 30,066.02 6,305 5,663 24,403 23.71 1,029 2004 28,191.47 5,018 4,507 23,684 24.66 960

62,738.82 15,090 13,554 49,184 2,261


V-30






1970 49,208.50 28,876 46,307 2,902 24.79 117 1980 591,366.80 269,190 431,690 159,677 32.69 4,885 1990 1,043,295.67 323,213 518,324 524,972 41.41 12,677 2000 11,382.63 1,755 2,814 8,569 50.75 169 2001 110,897.25 15,326 24,578 86,319 51.71 1,669 2003 22,383.42 2,368 3,798 18,585 53.65 346 2004 60,353.98 5,414 8,682 51,672 54.62 946 2009 113,856.77 934 1,498 112,359 59.51 1,888

2,002,745.02 647,076 1,037,691 965,055 22,697


V-31






1970 42,599.45 39,396 31,345 11,254 1.88 5,986 1980 62,554.34 50,018 39,796 22,758 5.01 4,543 1990 74,201.39 44,847 35,682 38,519 9.89 3,895 2000 16,193.52 5,240 4,169 12,025 16.91 711 2001 129,333.66 37,765 30,047 99,287 17.70 5,609 2002 36,369.01 9,441 7,512 28,857 18.51 1,559 2003 26,449.89 5,988 4,764 21,686 19.34 1,121 2004 52,991.12 10,217 8,129 44,862 20.18 2,223 2006 47,601.24 5,922 4,712 42,889 21.89 1,959 2007 123,160.53 11,035 8,780 114,381 22.76 5,026 2009 282,232.67 5,080 4,042 278,191 24.55 11,332

893,686.82 224,949 178,978 714,709 43,964


V-32


ACCOUNT 468.00 COMMUNICATION STRUCTURES & EQUIPMENT




1990 129,793.96 109,196 98,364 31,430 2.38 13,206

129,793.96 109,196 98,364 31,430 13,206


V-33


ACCOUNT 469.00 OTHER




2002 18,450.46 3,459 3,875 14,575 32.50 448

18,450.46 3,459 3,875 14,575 448


V-34






1970 2,182.78 1,118 2,183 36.59 60 1980 58,392.52 22,674 58,393 45.88 1,273 1990 4,319.64 1,117 4,320 55.60 78

64,894.94 24,909 64,896 1,411


V-35






1970 3,349.30 3,038 2,689 660 2.79 237 1980 105,346.88 83,256 73,691 31,656 6.29 5,033 1990 41,339.75 24,006 21,248 20,092 12.58 1,597 2000 22,675.72 6,855 6,067 16,609 20.93 794 2001 532.72 145 128 405 21.85 19 2002 79,207.03 19,065 16,875 62,332 22.78 2,736 2003 51,480.36 10,795 9,555 41,925 23.71 1,768 2004 45,401.39 8,081 7,153 38,248 24.66 1,551 2005 28,730.41 4,195 3,713 25,017 25.62 976 2006 31,690.30 3,613 3,198 28,492 26.58 1,072 2007 40,017.58 3,269 2,894 37,124 27.55 1,348 2008 15,473.94 758 671 14,803 28.53 519 2009 41,405.22 675 597 40,808 29.51 1,383

506,650.60 167,751 148,479 358,171 19,033


V-36






1970 448,636.25 289,909 262,154 186,482 17.69 10,542 1980 923,036.27 469,272 424,346 498,690 24.58 20,288 1990 1,058,173.40 370,572 335,095 723,078 32.49 22,255 2000 73,450.42 12,927 11,689 61,761 41.20 1,499 2001 146,496.77 23,117 20,904 125,593 42.11 2,982 2002 115,052.73 16,061 14,523 100,530 43.02 2,337 2003 78,203.94 9,494 8,585 69,619 43.93 1,585 2004 114,965.36 11,818 10,687 104,278 44.86 2,325 2005 182,058.33 15,366 13,895 168,163 45.78 3,673 2006 240,701.96 15,838 14,322 226,380 46.71 4,846 2007 283,035.34 13,303 12,029 271,006 47.65 5,687 2008 344,537.18 9,716 8,786 335,751 48.59 6,910 2009 522,958.51 4,916 4,445 518,514 49.53 10,469

4,531,306.46 1,262,309 1,141,460 3,389,845 95,398


V-37






1958 218,726.94 210,700 190,786 27,941 1.10 25,401 1970 19,063.89 16,141 14,615 4,449 4.60 967 1980 293,040.64 209,612 189,801 103,240 8.54 12,089 1990 880,509.47 459,010 415,629 464,880 14.36 32,373 2000 145,825.92 39,810 36,048 109,778 21.81 5,033 2001 285,108.25 70,051 63,430 221,678 22.63 9,796 2002 166,944.19 36,394 32,954 133,990 23.46 5,711 2003 274,427.91 52,141 47,213 227,215 24.30 9,350 2004 308,918.16 49,952 45,231 263,687 25.15 10,485 2005 45,593.32 6,064 5,491 40,102 26.01 1,542 2006 60,754.62 6,318 5,721 55,034 26.88 2,047 2007 42,050.04 3,141 2,844 39,206 27.76 1,412 2008 87,274.22 3,927 3,556 83,718 28.65 2,922 2009 55,835.03 838 759 55,076 29.55 1,864

2,884,072.60 1,164,099 1,054,078 1,829,994 120,992


V-38






1958 597,202.93 431,360 477,068 120,135 16.66 7,211 1970 14,840.19 8,708 9,631 5,209 24.79 210 1980 1,909,669.30 869,281 961,391 948,278 32.69 29,008 1990 1,707,078.69 528,853 584,891 1,122,188 41.41 27,099 2000 9,049.87 1,395 1,543 7,507 50.75 148 2001 110,687.48 15,297 16,918 93,769 51.71 1,813 2002 80,775.72 9,855 10,899 69,877 52.68 1,326 2003 160,729.78 17,005 18,807 141,923 53.65 2,645 2004 116,073.10 10,412 11,515 104,558 54.62 1,914 2005 172,914.55 12,709 14,056 158,859 55.59 2,858 2006 115,372.73 6,611 7,311 108,062 56.56 1,911 2007 144,854.01 5,939 6,568 138,286 57.54 2,403 2008 946,470.57 23,378 25,855 920,616 58.52 15,732 2009 2,082,668.18 17,078 18,888 2,063,780 59.51 34,680

8,168,387.10 1,957,881 2,165,341 6,003,047 128,958


V-39






1970 20,626.07 20,626 20,626 1980 332,360.78 315,078 243,892 88,469 1.04 85,066 1990 74,435.15 58,506 45,288 29,147 4.28 6,810 2002 4,183.56 1,483 1,148 3,036 12.91 235 2004 32,222.95 8,507 6,585 25,638 14.72 1,742 2006 5,719.36 972 752 4,967 16.60 299 2007 17,095.83 2,086 1,615 15,481 17.56 882 2009 17,928.10 439 340 17,588 19.51 901

504,571.80 407,697 320,246 184,326 95,935


V-40






1980 83,737.57 66,957 23,447 60,291 5.01 12,034 1990 275,429.78 166,470 58,293 217,137 9.89 21,955 2001 41,376.84 12,082 4,231 37,146 17.70 2,099 2002 1,262.60 328 115 1,148 18.51 62 2003 63,801.45 14,445 5,058 58,743 19.34 3,037 2004 7,581.06 1,462 512 7,069 20.18 350 2005 10,342.16 1,642 575 9,767 21.03 464 2006 14,920.89 1,856 650 14,271 21.89 652 2007 38,374.96 3,438 1,204 37,171 22.76 1,633 2008 26,750.00 1,445 506 26,244 23.65 1,110 2009 32,682.76 588 206 32,477 24.55 1,323

596,260.07 270,713 94,797 501,464 44,719


V-41






1970 84,388.09 78,042 69,577 14,811 1.88 7,878 1980 85,900.41 68,686 61,236 24,664 5.01 4,923 1990 124,055.12 74,979 66,846 57,209 9.89 5,785 2000 15,402.40 4,984 4,443 10,959 16.91 648 2008 72,422.52 3,911 3,487 68,936 23.65 2,915 2009 4,724.21 85 76 4,648 24.55 189

386,892.75 230,687 205,665 181,227 22,338


V-42






1970 7,226.85 7,227 7,227 1980 4,892.52 4,893 4,893 1990 30,543.55 30,544 30,544 2001 3,210.51 1,819 432- 3,643 6.50 560 2002 3,695.86 1,848 439- 4,135 7.50 551 2003 3,493.36 1,514 359- 3,852 8.50 453 2004 6,025.48 2,210 525- 6,550 9.50 689 2005 5,851.44 1,755 416- 6,267 10.50 597 2006 6,523.58 1,522 361- 6,885 11.50 599 2007 3,242.08 540 128- 3,370 12.50 270 2008 8,812.69 881 210- 9,023 13.50 668 2009 5,615.59 187 44- 5,660 14.50 390

89,133.51 54,940 39,750 49,385 4,777


V-43






1990 5,429.82 4,034 9,873 5,529- 2000 50,364.34 26,766 65,508 25,217- 2001 47,601.01 23,880 58,445 20,364- 2002 38,565.72 18,203 44,551 13,698- 2005 115,167.34 42,253 103,412 11,278- 2006 86,911.02 27,318 66,859 2,670 2007 8,675.76 2,112 5,169 1,772 2008 57,630.29 9,023 22,083 24,021

410,345.30 153,589 375,900 47,623-


V-44






1980 57,802.30 49,132 49,132 1990 63,987.36 45,758 54,389 2002 84,503.75 29,830 37,175 34,653 8.77 3,951 2003 36,808.56 11,429 14,243 17,044 9.52 1,790 2004 110,383.37 29,396 36,634 57,192 10.30 5,553 2006 26,439.59 4,585 5,714 16,760 11.94 1,404 2007 137,354.26 17,197 21,431 95,320 12.79 7,453 2008 153,705.33 11,667 14,540 116,110 13.66 8,500 2009 290,235.25 7,401 9,223 237,477 14.55 16,321

961,219.77 206,395 242,481 574,556 44,972


V-45






1970 9,072.33 9,072 9,072 1980 66,479.76 66,480 66,480 1990 138,188.68 134,734 118,279 19,910 0.50 19,910 2000 33,744.46 16,029 14,071 19,673 10.50 1,874 2001 54,152.26 23,015 20,204 33,948 11.50 2,952 2002 32,346.57 12,130 10,649 21,698 12.50 1,736 2003 41,311.94 13,426 11,786 29,526 13.50 2,187 2004 78,642.21 21,627 18,986 59,656 14.50 4,114 2005 29,869.04 6,721 5,900 23,969 15.50 1,546 2006 54,115.66 9,470 8,314 45,802 16.50 2,776 2007 26,564.13 3,321 2,915 23,649 17.50 1,351 2008 20,472.51 1,535 1,347 19,126 18.50 1,034 2009 15,886.01 397 349 15,537 19.50 797

600,845.56 317,957 288,352 312,494 40,277


V-46






1990 16,597.26 16,597 16,597 2000 7,768.14 7,768 7,768 2002 44,761.20 44,761 44,761 2004 4,248.76 4,249 4,249 2006 1,053.75 738 1,054

74,429.11 74,113 74,429


V-47






1970 41.57 42 42 1980 81,913.44 81,913 81,913 1990 39,906.98 39,907 39,907 2000 2,886.35 1,959 82- 2,968 4.50 660 2001 6,683.13 4,057 171- 6,854 5.50 1,246 2002 9,376.80 5,023 211- 9,588 6.50 1,475 2003 10,845.74 5,036 212- 11,058 7.50 1,474

151,654.01 137,937 121,186 30,468 4,855


V-48

PACIFIC NORTHERN GAS (N.E.) LTD. FORT ST. JOHN





1996 52,545.07 9,432 37,751 14,794 61.54 240

52,545.07 9,432 37,751 14,794 240


V-49






1996 15,352.66 6,781 6,086 9,267 16.75 553 1998 382,528.81 144,864 130,013 252,516 18.64 13,547 1999 67,163.42 23,286 20,899 46,264 19.60 2,360

465,044.89 174,931 156,998 308,047 16,460


V-50






1996 74,979.54 31,491 21,550 53,430 17.40 3,071

74,979.54 31,491 21,550 53,430 3,071


V-51






1996 2,398,329.95 521,157 1,254,050 1,144,280 46.96 24,367 1997 105,760.40 21,332 51,331 54,429 47.90 1,136 1998 492,662.93 91,537 220,263 272,400 48.85 5,576 1999 109,864.44 18,677 44,942 64,922 49.80 1,304 2000 78,580.79 12,117 29,157 49,424 50.75 974 2003 3,553.94 376 905 2,649 53.65 49 2006 22,367.96 1,282 3,085 19,283 56.56 341 2007 87,430.90 3,585 8,626 78,805 57.54 1,370 2008 65,003.79 1,606 3,865 61,139 58.52 1,045 2009 83,763.81 687 1,653 82,111 59.51 1,380

3,447,318.91 672,356 1,617,877 1,829,442 37,542


V-52






1996 1,871,037.78 832,238 1,038,421 832,617 13.88 59,987 1997 1,153.80 480 599 555 14.61 38 1999 346,928.58 123,090 153,585 193,344 16.13 11,987 2000 8,534.51 2,762 3,446 5,089 16.91 301 2005 39,809.13 6,322 7,888 31,921 21.03 1,518 2006 12,764.60 1,588 1,981 10,784 21.89 493 2007 242,299.56 21,710 27,089 215,211 22.76 9,456 2008 377,229.76 20,370 25,417 351,813 23.65 14,876 2009 219,910.21 3,958 4,939 214,971 24.55 8,756

3,119,667.93 1,012,518 1,263,365 1,856,305 107,412


V-53






1996 124,208.29 22,295 4,413 119,795 61.54 1,947 1997 2,005.35 333 66 1,939 62.53 31 1998 15,123.04 2,312 457 14,666 63.53 231

141,336.68 24,940 4,936 136,400 2,209


V-54






1996 32,700.45 13,734 10,568 22,132 17.40 1,272 1997 11,514.75 4,506 3,467 8,048 18.26 441 1998 4,951.41 1,792 1,379 3,572 19.14 187 2000 171,817.09 51,940 39,967 131,850 20.93 6,300 2001 93,565.06 25,422 19,562 74,003 21.85 3,387 2002 84,330.77 20,298 15,619 68,712 22.78 3,016 2003 104,898.99 21,997 16,926 87,973 23.71 3,710 2004 65,607.36 11,678 8,986 56,621 24.66 2,296 2005 42,405.46 6,191 4,764 37,641 25.62 1,469 2006 34,107.32 3,888 2,991 31,116 26.58 1,171 2007 42,084.73 3,438 2,645 39,440 27.55 1,432 2008 43,856.84 2,149 1,654 42,203 28.53 1,479 2009 124,470.27 2,029 1,561 122,909 29.51 4,165

856,310.50 169,062 130,089 726,220 30,325


V-55






1996 4,723,502.49 1,167,650 1,307,696 3,415,806 37.64 90,749 1997 522,456.43 119,956 134,343 388,113 38.52 10,076 1998 860,001.48 182,148 203,995 656,006 39.41 16,646 1999 507,688.90 98,492 110,305 397,384 40.30 9,861 2000 402,534.69 70,846 79,343 323,192 41.20 7,844 2001 362,194.16 57,154 64,009 298,185 42.11 7,081 2002 432,124.84 60,325 67,560 364,565 43.02 8,474 2003 410,451.58 49,829 55,805 354,647 43.93 8,073 2004 486,854.60 50,049 56,052 430,803 44.86 9,603 2005 485,495.49 40,976 45,891 439,604 45.78 9,603 2006 501,312.99 32,986 36,942 464,371 46.71 9,942 2007 700,248.02 32,912 36,859 663,389 47.65 13,922 2008 734,110.23 20,702 23,185 710,925 48.59 14,631 2009 422,851.07 3,975 4,452 418,399 49.53 8,447

11,551,826.97 1,988,000 2,226,437 9,325,389 224,952


V-56






1996 652,349.01 246,588 317,914 334,435 18.66 17,923 1997 155,053.05 54,625 70,425 84,628 19.43 4,356 1998 85,338.88 27,846 35,900 49,439 20.21 2,446 1999 38,068.61 11,421 14,725 23,344 21.00 1,112 2000 33,757.81 9,216 11,882 21,876 21.81 1,003 2001 44,161.11 10,850 13,988 30,173 22.63 1,333 2002 71,139.86 15,508 19,994 51,146 23.46 2,180 2003 33,315.56 6,330 8,161 25,155 24.30 1,035 2004 53,855.47 8,708 11,227 42,628 25.15 1,695 2005 51,684.21 6,874 8,862 42,822 26.01 1,646 2006 63,303.95 6,584 8,488 54,816 26.88 2,039 2007 79,573.50 5,944 7,663 71,911 27.76 2,590 2008 98,986.96 4,454 5,743 93,244 28.65 3,255 2009 64,598.57 969 1,249 63,350 29.55 2,144

1,525,186.55 415,917 536,221 988,967 44,757


V-57






1996 6,128,428.58 1,331,708 2,531,994 3,596,435 46.96 76,585 1997 785,757.66 158,487 301,333 484,425 47.90 10,113 1998 927,722.17 172,371 327,731 599,991 48.85 12,282 1999 651,958.48 110,833 210,728 441,230 49.80 8,860 2000 553,870.40 85,407 162,386 391,484 50.75 7,714 2001 679,840.92 93,954 178,636 501,205 51.71 9,693 2002 572,743.38 69,875 132,854 439,889 52.68 8,350 2003 556,088.45 58,834 111,862 444,226 53.65 8,280 2004 1,042,854.27 93,544 177,857 864,997 54.62 15,837 2005 788,200.67 57,933 110,149 678,052 55.59 12,197 2006 408,131.73 23,386 44,464 363,668 56.56 6,430 2007 558,669.74 22,905 43,549 515,121 57.54 8,952 2008 1,403,017.66 34,655 65,890 1,337,128 58.52 22,849 2009 826,776.27 6,780 12,891 813,885 59.51 13,676

15,884,060.38 2,320,672 4,412,324 11,471,736 221,818


V-58






1996 305.01 122 68 237 18.01 13

305.01 122 68 237 13


V-59






1996 384,330.84 230,214 228,174 156,157 8.02 19,471 2000 50,087.84 22,089 21,893 28,195 11.18 2,522 2001 72,283.62 28,805 28,550 43,734 12.03 3,635 2002 19,455.93 6,897 6,836 12,620 12.91 978 2003 28,851.23 8,944 8,865 19,986 13.80 1,448 2004 24,731.74 6,529 6,471 18,261 14.72 1,241 2005 2,397.93 522 517 1,881 15.65 120 2006 34,423.37 5,852 5,800 28,623 16.60 1,724 2007 23,007.99 2,807 2,782 20,226 17.56 1,152 2009 28,652.01 702 696 27,956 19.51 1,433

668,222.50 313,361 310,584 357,639 33,724


V-60






1996 715,956.37 318,457 239,801 476,155 13.88 34,305 1997 118,518.44 49,256 37,090 81,428 14.61 5,573 1999 48,575.29 17,235 12,978 35,597 16.13 2,207 2002 41,309.65 10,724 8,075 33,235 18.51 1,796 2003 53,070.21 12,015 9,048 44,022 19.34 2,276 2004 65,646.66 12,657 9,531 56,116 20.18 2,781 2005 15,658.38 2,487 1,873 13,785 21.03 655 2006 51,220.91 6,372 4,798 46,423 21.89 2,121 2007 63,735.57 5,711 4,301 59,435 22.76 2,611 2008 64,311.24 3,473 2,615 61,696 23.65 2,609 2009 72,599.32 1,307 984 71,615 24.55 2,917

1,310,602.04 439,694 331,094 979,507 59,851


V-61


ACCOUNT 479.00 OTHER DIST. EQUIPMENTS




1996 319.70- 123- 124- 196- 21.50 9- 1998 19,936.40 6,551 6,617 13,319 23.50 567

19,616.70 6,428 6,493 13,123 558


V-62






1996 1,337.59 240 178 1,160 61.54 19

1,337.59 240 178 1,160 19


V-63






1996 294,789.42 131,122 138,280 156,509 13.88 11,276 1997 390,207.68 162,170 171,023 219,185 14.61 15,002 1998 49,356.50 19,032 20,071 29,286 15.36 1,907 2000 23,187.89 7,504 7,914 15,274 16.91 903 2006 6,170.00 768 810 5,360 21.89 245 2008 21,166.02 1,143 1,205 19,961 23.65 844

784,877.51 321,739 339,303 445,575 30,177


V-64






1996 65,446.34 58,902 65,446 1997 48,840.18 40,699 48,840 1998 18,719.15 14,352 18,719 1999 747.85 523 748 2000 515.67 327 516 2001 17,505.43 9,920 17,505 2006 1,841.86 430 1,842 2008 1,640.28 164 1,641

155,256.76 125,317 155,257


V-65






1996 140,735.50 89,102 112,588 1997 27,585.05 16,836 22,068 1998 40,326.64 23,596 32,261 1999 9,226.33 5,156 7,381 2000 53,620.94 28,496 42,897 2004 107,452.90 43,720 85,962 2005 81,086.66 29,749 64,869 2006 144,164.66 45,314 115,332 2007 78,502.54 19,111 61,514 1,288 4.87 264 2008 47,755.01 7,477 24,067 14,137 5.63 2,511

730,456.23 308,557 568,939 15,425 2,775


V-66






1996 4,013.36 2,295 11 3,400 4.91 692 1999 25,480.27 12,014 56 21,602 6.68 3,234 2006 65,837.17 11,416 54 55,908 11.94 4,682 2007 6,948.38 870 4 5,902 12.79 461 2009 18,591.70 474 2 15,801 14.55 1,086

120,870.88 27,069 127 102,613 10,155


V-67






1996 171,749.92 115,931 128,923 42,827 6.50 6,589 1997 8,116.29 5,073 5,642 2,474 7.50 330 1998 31,401.13 18,056 20,079 11,322 8.50 1,332 1999 30,540.27 16,034 17,831 12,709 9.50 1,338 2000 43,537.58 20,680 22,997 20,541 10.50 1,956 2002 19,813.60 7,430 8,263 11,551 12.50 924 2003 27,669.37 8,993 10,001 17,668 13.50 1,309 2004 20,725.31 5,699 6,338 14,387 14.50 992 2005 24,991.41 5,623 6,253 18,738 15.50 1,209 2006 29,127.87 5,097 5,668 23,460 16.50 1,422 2007 17,802.98 2,225 2,474 15,329 17.50 876 2008 15,866.70 1,190 1,323 14,544 18.50 786 2009 45,471.30 1,137 1,265 44,206 19.50 2,267

486,813.73 213,168 237,057 249,756 21,330


V-68






1996 191,322.65 191,323 191,323 1997 435,158.79 435,159 435,159 1998 3,105.29 3,105 3,105 1999 56,352.76 56,353 56,353 2001 2,744.45 2,744 2,744 2002 49,266.00 49,266 49,266 2003 747.12 747 747 2004 3,574.38 3,574 3,574 2005 11,644.68 10,480 113,774- 125,419 0.50 125,419 2006 10,030.82 7,022 76,233- 86,264 1.50 57,509 2007 1,078.55 539 5,852- 6,931 2.50 2,772 2009 3,868.05 387 4,201- 8,069 4.50 1,793

768,893.54 760,699 542,211 226,683 187,493


V-69






1996 90,981.03 87,733 47,447 43,534 0.50 43,534 1998 3,465.62 2,847 1,540 1,926 2.50 770 2000 3,176.70 2,156 1,166 2,011 4.50 447 2001 14,328.27 8,699 4,704 9,624 5.50 1,750

111,951.62 101,435 54,857 57,095 46,501


V-70

PACIFIC NORTHERN GAS (N.E.) LTD. TUMBLER RIDGE





1980 275.00 107 275 45.88 6

275.00 107 275 6


V-71






1990 34,443.54 20,001 10,628 23,816 12.58 1,893 2009 0.70- 1- 29.51

34,442.84 20,001 10,628 23,815 1,893


V-72






1980 75,159.71 59,399 49,605 25,555 6.29 4,063

75,159.71 59,399 49,605 25,555 4,063


V-73






2000 29,701.25 9,611 8,019 21,682 16.91 1,282

29,701.25 9,611 8,019 21,682 1,282


V-74


ACCOUNT 418.00 PURIFICATION EQUIPMENT




1980 2,270,774.47 1,971,941 2,270,774 1990 120,879.38 81,328 102,629 18,250 8.18 2,231 2000 59,112.21 21,233 26,794 32,318 16.02 2,017 2001 84,502.30 27,345 34,507 49,995 16.91 2,957 2002 41,472.49 11,911 15,031 26,441 17.82 1,484 2003 41,105.45 10,276 12,967 28,138 18.75 1,501 2004 80,184.24 17,063 21,532 58,652 19.68 2,980 2005 112,335.11 19,636 24,779 87,556 20.63 4,244 2006 60,438.84 8,244 10,403 50,036 21.59 2,318 2007 111,076.30 10,885 13,736 97,340 22.55 4,317 2008 97,399.41 5,727 7,227 90,172 23.53 3,832 2009 156,349.01 3,064 3,867 152,482 24.51 6,221

3,235,629.21 2,188,653 2,544,246 691,380 34,102


V-75






1980 1,670,849.66 760,571 863,937 806,913 32.69 24,684 1990 45,285.95 14,030 15,937 29,349 41.41 709 2009 0.18-

1,716,135.43 774,601 879,874 836,262 25,393


V-76






1990 4,412.00 2,437 1,985 2,427 13.43 181

4,412.00 2,437 1,985 2,427 181


V-77






1990 47,405.79 28,652 20,043 27,363 9.89 2,767 2001 25,021.93 7,306 5,111 19,911 17.70 1,125 2003 4,783.52 1,083 758 4,026 19.34 208 2004 7,090.20 1,367 956 6,134 20.18 304 2008 20,448.59 1,104 772 19,677 23.65 832

104,750.03 39,512 27,640 77,111 5,236


V-78






1980 1,360.63 528 1,361 45.88 30 1990 650.00 168 650 55.60 12

2,010.63 696 2,011 42


V-79






1980 30,514.94 24,116 18,927 11,588 6.29 1,842 2001 6,537.72 1,776 1,394 5,144 21.85 235 2003 6,635.51 1,391 1,092 5,544 23.71 234 2005 14,429.58 2,107 1,653 12,777 25.62 499 2007 20,434.77 1,670 1,311 19,124 27.55 694 2008 126,979.80 6,222 4,883 122,097 28.53 4,280 2009 19,862.00 324 254 19,608 29.51 664

225,394.32 37,606 29,514 195,882 8,448


V-80






1980 411,864.29 209,392 206,164 205,700 24.58 8,369 1990 43,782.09 15,332 15,096 28,686 32.49 883 2001 338.72 53 52 287 42.11 7 2002 4,329.17 604 595 3,734 43.02 87 2003 16,102.55 1,955 1,925 14,178 43.93 323 2004 61,549.72 6,327 6,229 55,321 44.86 1,233 2005 7,610.15 642 632 6,978 45.78 152 2006 19,961.91 1,313 1,293 18,669 46.71 400 2007 13,711.21 644 634 13,077 47.65 274 2008 3,390.45 96 94 3,296 48.59 68 2009 8,058.37 76 75 7,983 49.53 161

590,698.63 236,434 232,789 357,909 11,957


V-81






1980 239,243.74 171,131 177,299 61,945 8.54 7,254 1990 10,969.58 5,718 5,924 5,046 14.36 351 2000 19.64 5 5 15 21.81 1 2002 567.56 124 129 439 23.46 19 2004 4,188.12 677 701 3,487 25.15 139 2005 1,017.77 135 140 878 26.01 34 2006 2,098.20 218 226 1,872 26.88 70 2007 624.11 47 49 575 27.76 21 2008 3,500.78 158 163 3,338 28.65 117 2009 967.66 15 16 952 29.55 32

263,197.16 178,228 184,652 78,547 8,038


V-82






1980 943,551.11 429,504 438,789 504,762 32.69 15,441 1990 15,994.88 4,955 5,062 10,933 41.41 264 2007 24,750.46 1,015 1,037 23,713 57.54 412

984,296.45 435,474 444,888 539,408 16,117


V-83






1980 188,024.57 178,247 160,592 27,433 1.04 26,378 2006 5,766.32 980 883 4,883 16.60 294

193,790.89 179,227 161,475 32,316 26,672


V-84






1980 215,435.42 172,262 154,309 61,126 5.01 12,201 2004 13,143.49 2,534 2,270 10,873 20.18 539 2006 10,552.55 1,313 1,176 9,377 21.89 428 2009 8,897.05 160 143 8,754 24.55 357

248,028.51 176,269 157,898 90,130 13,525


V-85






1980 392,102.83 313,525 342,973 49,130 5.01 9,806 1990 10,209.53 6,171 6,751 3,459 9.89 350

402,312.36 319,696 349,724 52,589 10,156


V-86






1980 4,797.94 4,798 4,798 1990 15,677.98 15,678 15,678 2001 2,782.00 1,577 1,831- 4,613 6.50 710 2003 2,311.20 1,001 1,162- 3,473 8.50 409 2004 1,814.53 665 772- 2,587 9.50 272 2005 716.47 215 250- 966 10.50 92 2006 2,872.10 670 778- 3,650 11.50 317

30,972.22 24,604 15,683 15,289 1,800


V-87






2001 2,041.00 1,024 2,958 1,325- 2002 34,349.53 16,213 46,833 19,353- 2007 45,150.24 10,991 31,749 4,371

81,540.77 28,228 81,540 16,307-


V-88






1990 35,209.00 25,178 29,767 161 2.38 68 2003 1,773.74 551 651 857 9.52 90 2009 64,794.36 1,652 1,953 53,122 14.55 3,651

101,777.10 27,381 32,371 54,140 3,809


V-89






1980 27,550.81 27,551 27,551 1990 19,403.96 18,919 15,638 3,766 0.50 3,766 2000 268.47 128 106 162 10.50 15 2001 3,550.80 1,509 1,247 2,304 11.50 200 2002 248.62 93 77 172 12.50 14 2003 3,168.74 1,030 851 2,318 13.50 172 2004 2,774.67 763 631 2,144 14.50 148 2005 5,598.10 1,260 1,042 4,556 15.50 294 2006 9,241.00 1,617 1,336 7,905 16.50 479 2008 14,980.00 1,124 929 14,051 18.50 760 2009 4,193.30 105 87 4,106 19.50 211

90,978.47 54,099 49,495 41,484 6,059


V-90






1990 8,214.17 8,214 8,214 2002 16,332.00 16,332 16,332 2006 1,711.67 1,198 1,712

26,257.84 25,744 26,258


V-91






1980 109,700.08 109,700 109,700 1990 5,882.88 5,883 5,883 2007 1,794.63 321 1,350- 3,145 11.50 273

117,377.59 115,904 114,233 3,145 273


V-92

Date post:	13-Sep-2020
Category:	Documents
Upload:	others
View:	0 times
Download:	0 times