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
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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
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
Utilityman 2Utilityman 5
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
Utilityman 1Utilityman 1
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
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
870 Supervision872 Structures and Improvements874 Equipment on Customers' Premises875 Mains and Sdrvices876 Compressor877 Measuring and Regulating878 Meters879 Other Distribution Maintenance
GENERAL MAINTENANCE
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Pacific Northern Gas Ltd. andPacific Northern Gas (N.E.) Ltd.
BCUC Code of Accounts
BCUC AccountCode Description
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
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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
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%)
A composite average of
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
Non-labour component
168,323 365,870
Customer Count 81,096
48.2%
(-%)(3)
Updated customer count Yes
685 – Terrace Management
Labour component
878,223
Time-based 324,064 36.9%
(48.2%) Updated time study results Yes
Non-labour component
263,540
1,141,763
Composite Average
Allocator A(2) 88,938
33.7% (-%)
A composite average of
relevant allocators
Yes
6
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
685 – Terrace Safety & Training (formerly Terrace Engineering)
Yes Non-labour component
87,427
Composite Average
Allocator C(2) 28,585
32.7% (20.8%)
A composite average of
relevant allocators
728 – Vancouver Corporate Expenses
Yes Non-labour
component
519,588
Composite Average
Allocator C(2) 169,886
32.7% (26.1%)
A composite average of
relevant allocators
7
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?
713 – Vancouver Vertex Billing Services
Non-labour component
946,986
Customer count 456,142
48.2% (48.2%)
Updated customer count Yes
722 – Vancouver Special Services
Non-labour component
253,055
Composite Average
Allocator C(2) 82,740
32.7% (32.5%)
A composite average of
relevant allocators
Yes
723 – Vancouver Insurance
Non-labour component
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
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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.
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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.
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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.
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.
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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
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.
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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.
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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.
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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:
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(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;
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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.
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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).
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Procedure Findings (see Table 2)
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.
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Procedure Findings (see Table 2)
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.
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Procedure Findings (see Table 2)
(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.
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Procedure Findings (see Table 2)
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.
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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.
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Table 2b – Summary of Shared Service Cost Pools
Shared Service Cost Pool
Cost Pool Consistent with
Principles in Appendix A
Total $ Value of Proposed Cost
Pool (1)
Cost Pool is Relevant and Appropriate / Principles are Met
685 – Terrace Safety & Training (formerly Terrace Engineering)
Yes 87,427 Yes
728 – Vancouver Corporate Expenses
Yes 519,588 Yes
713 – Vancouver Vertex Billing Services
Yes 946,986 Yes
722 – Vancouver Special Services
Yes 253,055 Yes
723 – Vancouver Insurance
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.
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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.
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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
721 – Vancouver Administration
Labour component Time- based Time-based Yes-S
Non- labour components Time- based Composite
Average Allocator A(1)
Yes-S
711/713/714 – Terrace Customer Care Centre
Labour component Customer count Time-based Yes-S
Non-labour component Customer count Composite Average
Allocators B(1) Yes-S
711/713/714 – Vancouver Billing Services (new)
Labour component Customer count Customer Count 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.
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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
721 – Vancouver Administration
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
711/713/714 – Terrace Customer Care Centre
Labour component Time- based
554,169 49.2% (48.2%) Yes
Non-labour component
Composite Average Allocators B(2)
77,047 48.7% (48.2%) Yes
711/713/714 – Vancouver Billing Services (new)
Labour component Customer Count 95,176 48.2%(3) (-%)(3) Yes
Non-labour component
Customer Count 81,096 48.2% (-%)(3) Yes
685 – Terrace Management
Labour component Time-based 324,064 36.9% (48.2%) Yes
Composite Average Allocator C(2) 67,108 32.7% (-%)(4) Yes
685 – Terrace Drafting
Non-labour component
Composite Average Allocator C(2) 23,068 32.7% (48.2%) Yes
685 – Terrace Safety & Training (formerly Terrace Engineering)
Non-labour component
Composite Average Allocator C(2) 28,585 32.7% (20.8%) Yes
728 – Vancouver Corporate Expenses
Non-labour component
Composite Average Allocator C(2)
169,886 32.7% (26.1%) Yes
713 – Vancouver Vertex Billing Services
Non-labour component
Customer count 456,142 48.2% (48.2%) Yes
722 – Vancouver Special Services
Non-labour component
Composite Average Allocator C(2)
82,740 32.7% (32.5%) Yes
723 – Vancouver Insurance
Non-labour component
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)
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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.
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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.
Completed. No issues were noted.
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.
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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.
Completed. No issues were noted.
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.
Completed. No issues were noted.
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.
Completed. No issues were noted.
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.
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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.
Completed. No issues were noted.
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.
Completed. No issues were noted.
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.
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Appendix A – PNG’s Shared Services Cost Allocation Principles
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.
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.
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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
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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:
685 – Terrace Safety & Training (formerly Terrace Engineering)
Yes Yes 198,844 87,427 (111,417)
728 – Vancouver Corporate Expenses
Yes Yes 519,588 519,588 –
713 – Vancouver Vertex Billing Services
Yes Yes 946,986 946,986 –
722 – Vancouver Special Services
Yes Yes 223,914 253,055 29,141
723 – Vancouver Insurance
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.
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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.
721 – Vancouver Administration
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:
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;
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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.
711/713/714 – Terrace Customer Care Centre
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;
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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
711/713/714 – Vancouver Billing Services (new)
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.
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685 – Terrace Management
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.
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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.
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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.
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.
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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.
685 – Terrace Drafting
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.
685 – Terrace Safety & Training (formerly Terrace Engineering)
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.
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728 – Vancouver Corporate Expenses
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.
711 – Vancouver Vertex Billing Services
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
PNG Management’s review of costs included in this cost pool indicates that all relevant costs have been captured and no changes are proposed.
722 – Vancouver Special Services
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.
723 – Vancouver Insurance
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
PNG Management’s review of costs included in this cost pool indicates that all relevant costs have been captured and no changes are proposed.
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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).
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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.
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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.
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Table B - Summary of Shared Service Cost Allocators
Shared Service Cost Pool (see Table 1 also)
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
Total $ Value of Proposed Cost
Pool Allocated to NE Using Proposed
Allocators(1)
% of Proposed Cost Pool Allocated to NE
Using Proposed Allocators
Explanation of Proposed Cost
Allocator Amendments
Are the proposed allocators and final
allocation reasonable and consistent with
PNG’s allocation principles?
721 – Vancouver Administration
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
711/713/714 – Terrace Customer Care Centre
Labour component Customer
count Time- based
656,780 48.2% 554,169 49.2% Updated time study results Yes
Non-labour component
Customer count
Composite Average
Allocators B(2) 134,551 48.2% 77,047 48.7% A composite average of
(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.
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).
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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;
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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
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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.
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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
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
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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.
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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%
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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:
Report Structure Tables 2 and 3 below describe the sections and appendices in this report.
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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
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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.
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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.
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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
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Activity/Category Description Drivers
Corporate (administration):
Management Salary 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 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
• Estimated cost of staff time and associated benefit costs devoted to capital activities
• 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
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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
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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.
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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;
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• 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.
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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.
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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
Evaluation Criteria Assessment Explanation
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.
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Evaluation Criteria Assessment Explanation
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.
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Evaluation Criteria Assessment Explanation
• 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
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• 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.
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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.
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%
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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
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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
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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.
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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.
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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.
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• 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.
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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.
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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
Percentage of Operating, Maintenance, Administrative and General Costs 4.30% 8.71% 1.32% 0.95%
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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.
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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.
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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.
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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
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(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.
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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.
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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.
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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
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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.
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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?
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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.
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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.
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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
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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
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
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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
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)
60.0% 60.0% 60.0% Capital Overhead Management time on capital activities is considered to be incremental to capital projects
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
25.0% 35.0% 30.0% Capital Overhead Management time on capital activities is considered to be incremental to capital projects
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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
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
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, 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
3.0% 5.0% 4.0% 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 spent on capital budgeting, cost monitoring and regulatory process
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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
93/99/90 – Finance
Direct: None – no direct involvement in capital projects
3.0% 6.0% 4.5% 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 spent on capital budgeting, fixed asset accounting and rate and regulatory applications
91/92/89 – Operations & Engineering
Direct: None – no direct involvement in capital projects
33.0% 50.0% 41.5% Capital Overhead Management time on capital activities is considered to be incremental to capital projects
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
Direct: None – no direct involvement in capital projects
8.0% 12.0% 10.0% 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: Capital project financing; rate applications; investor relations
97 – Information Technology
Direct: No activities charged; capital purchases made
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: IT-related capital projects (product assessment, supplier quotes, coordination of install)
94/96 – Regulatory Affairs
Direct: None – no direct involvement in capital projects
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
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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
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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.
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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
allocate cost to capital projects on a pro rata basis of project capital cost over total capital costs for period.
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
allocate cost to capital projects on a pro rata basis of project capital cost over total capital costs for period.
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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.
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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:
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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
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
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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
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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
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
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
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
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
PART I. INTRODUCTION
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
PART I. INTRODUCTION
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
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)
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
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32
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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.
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ND
RIG
HTS
75-R
40
64,8
94.9
4
-
64,8
95
1,41
1
2.
17
46
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2.00
STR
UC
TUR
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& IM
PR
OV
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EN
TS30
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050
6,65
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14
8,47
9
358,
172
19
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76
18
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3.00
SE
RV
ICE
S50
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50
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1,14
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0
3,
389,
846
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98
2.11
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SE
RE
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NS
TALL
ATI
ON
S30
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884,
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60
1,
054,
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12
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10
2,
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6,00
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6
12
8,95
8
1.58
46.6
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SU
RIN
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RE
GU
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EQ
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ME
NT
20-R
30
504,
571.
80
320,
246
18
4,32
6
36,8
65
7.31
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(*)
478.
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RS
25-R
20
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260.
07
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50
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LAN
T17
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4,
924,
401
12,3
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43
447,
376
GEN
ERAL
PLA
NT
482.
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TRU
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S &
IMP
RO
VE
ME
NTS
25-R
20
386,
892.
75
205,
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18
1,22
8
22,3
38
5.77
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483.
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EQ
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1
39
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84
4,77
7
5.
36
10
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4.00
TRA
NS
PO
RT
EQ
UIP
ME
NT
7-L1
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041
0,34
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37
5,90
0
(47,
623)
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-
0.
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5.00
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AV
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QU
IPM
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961,
219.
77
242,
481
57
4,55
6
44,9
72
4.68
12.8
486.
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OR
K E
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T20
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060
0,84
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28
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2
312,
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40
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6.
70
7.
848
7.00
CO
MP
UTE
R E
QU
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EN
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074
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29
0
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-
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488.
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MU
NIC
ATI
ON
STR
UC
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151,
654.
01
121,
186
30
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4,
855
3.20
6.3
TOTA
L G
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ER
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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
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4,62
6
15
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8
2.78
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47
0.00
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D25
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650.
01
TOTA
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ON
- D
EP
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CIA
BLE
PLA
NT
30,5
84.1
7
TOTA
L P
LAN
T23
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.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
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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
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AT
DEP
REC
IATI
ON
FUTU
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AC
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UA
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CC
RU
AL
REM
AIN
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D
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BLE
WO
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RVE
SALV
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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
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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
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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
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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
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2.00
STR
UC
TUR
ES &
IMPR
OVE
MEN
TS30
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085
6,31
0.50
13
0,08
9
726,
222
30
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3.
54
23
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3.00
SER
VIC
ES50
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50
11,5
51,8
26.9
7
2,22
6,43
7
9,
325,
390
224,
952
1.
95
41
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4.00
HO
USE
REG
. IN
STAL
LATI
ON
S30
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01,
525,
186.
55
53
6,22
1
988,
966
44
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2.
93
22
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5.00
MAI
NS
60-R
30
15,8
84,0
60.3
8
4,41
2,32
4
11
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22
1,81
8
1.40
51.7
476.
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OM
PRES
SOR
EQ
UIP
MEN
T30
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50
305.
01
68
23
7
13
4.
26
18
.247
7.00
MEA
SUR
ING
& R
EGU
LATI
NG
EQ
UIP
MEN
T20
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066
8,22
2.50
31
0,58
4
357,
639
33
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5.
05
10
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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.
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THER
DIS
T. E
QU
IPM
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35-S
Q0
19,6
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0
6,
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24
558
2.
84
23
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TOTA
L D
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TIO
N P
LAN
T31
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7,
958,
246
23,9
99,2
21
618,
207
GEN
ERA
L PL
AN
T48
1.00
LAN
D R
IGH
TS75
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01,
337.
59
17
8
1,16
0
19
1.42
61.1
482.
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RU
CTU
RES
& IM
PRO
VEM
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25-R
20
784,
877.
51
339,
303
44
5,57
5
30,1
77
3.84
14.8
483.
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RN
ITU
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/ EQ
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MEN
T15
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015
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15
5,25
7
(0)
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-
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T EQ
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MEN
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730,
456.
23
568,
939
15
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2,
775
0.38
5.6
485.
00H
EAVY
WO
RK
EQU
IPM
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15-R
2+1
512
0,87
0.88
12
7
102,
613
10
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8.
40
10
.148
6.00
TOO
LS /
WO
RK
EQU
IPM
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20-S
Q0
486,
813.
73
237,
057
24
9,75
7
21,3
30
4.38
11.7
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OM
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R E
QU
IPM
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076
8,89
3.54
54
2,21
1
226,
683
45
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5.
90
5.
0(*
)48
8.00
CO
MM
UN
ICAT
ION
STR
UC
TUR
ES &
EQ
UIP
.14
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011
1,95
1.62
54
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57,0
95
11,4
19
10.2
0
5.0
(*)
TOTA
L G
ENER
AL P
LAN
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160,
457.
86
1,
897,
929
1,09
8,30
6
12
1,21
1
TOTA
L D
EPR
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PLAN
T42
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12
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29
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4,14
3
2.14
PLA
NT
NO
T ST
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460.
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ND
6,39
5.28
470.
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ND
11,9
16.3
6
48
0.00
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D76
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TOTA
L N
ON
- D
EPR
ECIA
BLE
PLAN
T94
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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 -
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MA
TED
SU
RVI
VOR
CU
RVE
, OR
IGIN
AL
CO
ST, B
OO
K D
EPR
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TIO
N R
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VE A
ND
CA
LCU
LATE
DA
NN
UA
L D
EPR
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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
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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
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2.00
STR
UC
TUR
ES
& IM
PR
OV
EM
EN
TS30
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034
,442
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10,6
28
23
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1,
893
5.50
12.6
413.
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EA
SU
RIN
G &
RE
GU
LATI
NG
STR
UC
TUR
ES
30-R
30
75,1
59.7
1
49
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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
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029
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8,01
9
21
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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
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01,
716,
135.
43
87
9,87
4
836,
261
25
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1.
48
32
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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.
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EA
SU
RIN
G &
RE
GU
LATI
NG
EQ
UIP
ME
NT
25-R
20
104,
750.
03
27,6
40
77
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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
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2.00
STR
UC
TUR
ES
& IM
PR
OV
EM
EN
TS30
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022
5,39
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29
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195,
880
8,
448
3.75
23.2
473.
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ES
50-R
2.5
059
0,69
8.63
23
2,78
9
357,
910
11
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2.
02
29
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4.00
HO
US
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EG
. IN
STA
LLA
TIO
NS
30-R
20
263,
197.
16
184,
652
78
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8,
038
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475.
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S60
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098
4,29
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44
4,88
8
539,
408
16
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1.
64
33
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7.00
ME
AS
UR
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& R
EG
ULA
TIN
G E
QU
IPM
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T20
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019
3,79
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16
1,47
5
32,3
16
6,46
3
3.
34
5.
0(*
)47
8.00
ME
TER
S25
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024
8,02
8.51
15
7,89
8
90,1
31
13,5
25
5.45
6.7
TOTA
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416.
59
1,
211,
216
1,29
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1
64
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GEN
ERA
L PL
AN
T48
2.00
STR
UC
TUR
ES
& IM
PR
OV
EM
EN
TS25
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040
2,31
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34
9,72
4
52,5
88
10,1
56
2.52
5.2
483.
00O
FFIC
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UR
NIT
UR
E /
EQ
UIP
ME
NT
15-S
Q0
30,9
72.2
2
15
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15,2
89
1,80
0
5.
81
8.
548
4.00
TRA
NS
PO
RT
EQ
UIP
ME
NT
7-L1
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081
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81,5
40
(1
6,30
7)
-
-
0.0
485.
00H
EA
VY
WO
RK
EQ
UIP
ME
NT
15-R
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510
1,77
7.10
32
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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
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41,4
83
6,05
9
6.
66
6.
848
7.00
CO
MP
UTE
R E
QU
IPM
EN
T5-
SQ
026
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26,2
58
(0
)
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-
0.
048
8.00
CO
MM
UN
ICA
TIO
N S
TRU
CTU
RE
S &
EQ
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.14
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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,
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158,
843
1.
86
PLA
NT
NO
T ST
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410.
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ND
3,08
9.40
460.
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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