DECISION  
NSUARB-NSPI-P-882  
2006 NSUARB 23  
NOVA SCOTIA UTILITY AND REVIEW BOARD  
IN THE MATTER OF THE PUBLIC UTILITIES ACT  
- and -  
IN THE MATTER OF AN APPLICATION by Nova Scotia Power Incorporated for  
approval of certain Revisions to its Rates, Charges and Regulations  
BEFORE:  
John A. Morash, C.A., Panel Chair  
Roland A. Deveau, Member  
Kulvinder S. Dhillon, P. Eng., Member  
COUNSEL:  
NOVA SCOTIA POWER INCORPORATED  
James L. Connors, Q.C.  
Rene Gallant  
AFFORDABLE ENERGY COALITION  
Claire McNeil  
Megan Leslie  
AVON VALLEY GREENHOUSES LTD., et al.  
Robert G. Grant, Q.C.  
Nancy G. Rubin  
CANADIAN MANUFACTURERS & EXPORTERS  
Robert Patzelt  
CONSUMER ADVOCATE  
John P. Merrick, Q.C.  
William L. Mahody  
ECOLOGY ACTION CENTRE  
Ceilidh Auger-Day  
ELECTRICITY CONSUMERS ALLIANCE  
OF NOVA SCOTIA  
John Woods, P. Eng.  
Document : 112539  
GASWORKS ENERGY CORP.  
John Reynolds, P. Eng.  
HALIFAX REGIONAL MUNICIPALITY  
Mary Ellen Donovan  
DR. LARRY HUGHES, Ph.D  
LIBERAL CAUCUS OFFICE (NOVA SCOTIA)  
Danny Graham, MLA  
David Macrury  
MUNICIPAL ELECTRIC UTILITIES  
OF NOVA SCOTIA CO-OPERATIVE  
Albert Dominie  
NEW DEMOCRATIC PARTY CAUCUS OFFICE  
Howard Epstein, MLA  
PROVINCE OF NOVA SCOTIA  
(Department of Energy)  
Stephen T. McGrath  
STORA ENSO PORT HAWKESBURY LIMITED and  
BOWATER MERSEY PAPER COMPANY LIMITED  
George T. H. Cooper, Q.C.  
David S. MacDougall  
HEARING DATES:  
November 14-17, 22-25, 28-30 and December 1-2, 2005  
FINAL SUBMISSIONS:  
LIST OF WITNESSES:  
December 22, 2005  
APPENDIX - A  
LIST OF INTERVENORS:  
BOARD COUNSEL:  
APPENDIX - B  
S. Bruce Outhouse, Q.C.  
March 10, 2006  
DECISION DATE:  
Document : 112539  
DECISION:  
Requested Revenue Requirement increase of  
approximately $106 million, after reflecting the natural  
gas settlement agreement, reduced to approximately  
$61 million; Proposed average rate increase for above-  
the-line customers of approximately 13%, reduced to  
approximately 8.6%, with an 8.9% increase for domestic  
customers, effective March 10, 2006; Annually adjusted  
rates to increase effective January 1, 2006, as  
determined by the Compliance Filing  
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TABLE OF CONTENTS  
1.0  
2.0  
3.0  
INTRODUCTION.................................................................................................. 1  
BACKGROUND ................................................................................................... 5  
FUEL ISSUES.................................................................................................... 11  
3.1  
3.2  
General Overview.................................................................................... 11  
Fuel Procurement Strategy...................................................................... 15  
3.2.1 Overview....................................................................................... 15  
3.2.2 Submissions - NSPI ...................................................................... 16  
3.2.3 Submissions - Liberty and Intervenors.......................................... 19  
3.2.4 Findings ........................................................................................ 29  
Carryover of Imprudency ......................................................................... 34  
3.3.1 Overview....................................................................................... 34  
3.3.2 Submissions - NSPI ...................................................................... 37  
3.3.3 Submissions - Intervenors and Board Counsel Witnesses............ 43  
3.3.4 Findings ........................................................................................ 49  
Long-Term Contract................................................................................. 53  
3.4.1 Submissions - NSPI ...................................................................... 53  
3.4.2 Submissions - Intervenors and Liberty.......................................... 55  
3.4.3 Findings ........................................................................................ 60  
Affiliate Activity......................................................................................... 64  
3.5.1 Submissions - NSPI ...................................................................... 64  
3.5.2 Submissions - Liberty.................................................................... 68  
3.5.3 Findings ........................................................................................ 76  
Point Tupper Marine Terminal ................................................................. 80  
3.6.1 Submissions - NSPI ...................................................................... 80  
3.6.2 Submissions - Intervenors and Liberty.......................................... 84  
3.6.3 Findings ........................................................................................ 89  
Natural Gas Resale Benefit ..................................................................... 92  
3.7.1 Submissions - NSPI ...................................................................... 92  
3.7.2 Submissions - Dr. Stutz and Intervenors..................................... 100  
3.7.3 Findings ...................................................................................... 106  
Fuel Costs.............................................................................................. 113  
3.8.1 Submissions - NSPI .................................................................... 113  
3.8.2 Submissions - Intervenors and Liberty........................................ 115  
3.8.3 Findings ...................................................................................... 120  
3.3  
3.4  
3.5  
3.6  
3.7  
3.8  
4.0  
FINANCE.......................................................................................................... 122  
4.1  
Return on Equity.................................................................................... 122  
4.1.1 Findings ...................................................................................... 122  
Capital Structure.................................................................................... 123  
4.2  
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4.2.1 Findings ...................................................................................... 123  
5.0  
RATE BASE..................................................................................................... 124  
5.1  
5.2  
Overview................................................................................................ 124  
HST........................................................................................................ 126  
5.2.1 Submissions - NSPI .................................................................... 126  
5.2.2 Submissions - Intervenors........................................................... 127  
5.2.3 Findings ...................................................................................... 128  
Interest Expense and Preferred Dividends ............................................ 130  
5.3.1 Submissions - NSPI .................................................................... 130  
5.3.2 Submissions - Intervenors........................................................... 133  
5.3.3 Findings ...................................................................................... 134  
Securitization of Accounts Receivable................................................... 138  
5.4.1 Submissions - NSPI .................................................................... 138  
5.4.2 Submissions - Intervenors........................................................... 141  
5.4.3 Findings ...................................................................................... 143  
Other Lead/Lag Assumptions ................................................................ 144  
5.5.1 Submissions - NSPI .................................................................... 144  
5.5.2 Submissions - Intervenors........................................................... 145  
5.5.3 Findings ...................................................................................... 148  
Total Rate Base..................................................................................... 152  
5.3  
5.4  
5.5  
5.6  
6.0  
OPERATING, MAINTENANCE AND GENERAL EXPENSES (OM&G).......... 154  
6.1  
6.2  
Overview................................................................................................ 154  
Power Production .................................................................................. 155  
6.2.1 Submissions - NSPI .................................................................... 155  
6.2.2 Submissions - Intervenors........................................................... 157  
6.2.3 Findings ...................................................................................... 157  
Customer Operations............................................................................. 159  
6.3.1 Submissions - NSPI .................................................................... 159  
6.3.2 Submissions - Intervenors and PWC .......................................... 164  
6.3.3 Findings ...................................................................................... 168  
Corporate Support Groups (excluding DSM) ......................................... 179  
6.4.1 Submissions - NSPI .................................................................... 179  
6.4.2 Submissions - Intervenors and PWC .......................................... 183  
6.4.3 Findings ...................................................................................... 186  
Corporate Adjustments .......................................................................... 192  
6.5.1 Submissions - NSPI .................................................................... 192  
6.5.2 Submissions - PWC and Intervenors .......................................... 193  
6.5.3 Findings ...................................................................................... 195  
Summary of OM&G Findings................................................................. 196  
OM&G - Operations Review .................................................................. 197  
6.7.1 Submissions - NSPI .................................................................... 197  
6.7.2 Submissions - Intervenors and PWC .......................................... 200  
6.3  
6.4  
6.5  
6.6  
6.7  
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6.7.3 Findings ...................................................................................... 202  
7.0  
DEMAND SIDE MANAGEMENT ..................................................................... 209  
7.1.1 Overview..................................................................................... 209  
7.1.2 Submissions - NSPI .................................................................... 209  
7.1.3 Submissions - Intervenors and Dr. John Stutz............................ 212  
7.1.4 Findings ...................................................................................... 221  
8.0  
9.0  
DEPRECIATION .............................................................................................. 226  
8.1.1 Submissions - NSPI .................................................................... 226  
8.1.2 Submissions - Intervenors........................................................... 226  
8.1.3 Findings ...................................................................................... 227  
RATES ............................................................................................................. 229  
9.1.1 Overview..................................................................................... 229  
10.0 ANNUALLY ADJUSTED RATES/BELOW-THE-LINE RATES........................ 230  
10.1 Overview................................................................................................ 230  
10.2 Generation Replacement and Load Following Rate............................... 230  
10.2.1 Submissions - NSPI................................................................... 231  
10.2.2 Submissions - Intervenors ......................................................... 231  
10.2.3 Findings ..................................................................................... 232  
10.3 Real Time Pricing Rate (1P-RTP).......................................................... 232  
10.3.1 Submissions - NSPI................................................................... 232  
10.3.2 Findings ..................................................................................... 234  
10.4. Two Part Real Time Price Rate (2P-RTP) ............................................. 234  
10.4.1 Submissions - NSPI................................................................... 234  
10.4.2 Submissions - Intervenors ......................................................... 236  
10.4.3 Findings ..................................................................................... 237  
10.5 Extra Large Industrial Interruptible Rate (ELIIR).................................... 243  
10.5.1 Submissions - NSPI................................................................... 243  
10.5.2 Submissions - Intervenors and Dr. Stutz.................................... 246  
10.5.3 Findings ..................................................................................... 257  
11.0 OTHER ISSUES............................................................................................... 260  
11.1 Load Forecast........................................................................................ 260  
11.1.1 Findings ..................................................................................... 264  
11.2 Unmetered Rates................................................................................... 266  
11.2.1 Findings ..................................................................................... 269  
11.3 Miscellaneous Charges.......................................................................... 269  
11.3.1 Findings ..................................................................................... 272  
11.4 Low Income Consumers ........................................................................ 273  
11.4.1 Findings ..................................................................................... 275  
11.5 Pole Attachment Fees............................................................................ 276  
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11.5.1 Findings ..................................................................................... 277  
11.6 Renewable and Environmentally Sustainable Energy............................ 277  
11.6.1 Findings ..................................................................................... 279  
11.7 Incentive Compensation Plan Review.................................................... 279  
11.7.1 Findings ..................................................................................... 281  
11.8 Non-Profit Intervenor Costs ................................................................... 281  
11.8.1 Findings ..................................................................................... 282  
11.9 General Demand Rate Class................................................................. 282  
11.9.1 Findings ..................................................................................... 283  
12.0 SUMMARY OF DISALLOWANCES AND ADJUSTMENTS............................ 284  
13.0 FINANCIAL HEALTH OF NSPI ....................................................................... 288  
13.1 Submissions - NSPI............................................................................... 288  
13.2 Submissions - Intervenors ..................................................................... 291  
13.3 Findings ................................................................................................. 292  
14.0 SUMMARY OF BOARD FINDINGS................................................................. 295  
14.1 Financial Health of NSPI........................................................................ 295  
14.2 Fuel Procurement Strategy.................................................................... 296  
14.3 Carryover of Imprudency ....................................................................... 297  
14.4 Long-Term Contract............................................................................... 298  
14.5 Affiliate Activity....................................................................................... 298  
14.6 Point Tupper Marine Terminal ............................................................... 299  
14.7 Natural Gas Resale Benefit ................................................................... 299  
14.8 Fuel Costs.............................................................................................. 300  
14.9 Return on Equity.................................................................................... 301  
14.10 Capital Structure.................................................................................... 301  
14.11 Rate Base.............................................................................................. 301  
14.12 Operating, Maintenance and General Expenses (OM&G)..................... 302  
14.13 Operations Review................................................................................. 305  
14.14 Demand Side Management ................................................................... 305  
14.15 Depreciation........................................................................................... 306  
14.16 Annually Adjusted Rates/Below-the-Line Rates..................................... 306  
14.17 Load Forecast........................................................................................ 309  
14.18 Unmetered Rates................................................................................... 309  
14.19 Miscellaneous Charges.......................................................................... 310  
14.20 Low Income Consumers ........................................................................ 310  
14.21 Pole Attachment Fees............................................................................ 310  
14.22 Renewable and Environmentally Sustainable Energy............................ 311  
14.23 Incentive Compensation Plan Review.................................................... 311  
14.24 Non-Profit Intervenor Costs ................................................................... 311  
14.25 General Demand Rate Class................................................................. 312  
14.26 Disallowances and Adjustments/Rate Increase..................................... 312  
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APPENDICES  
Appendix - A List of Witnesses  
Appendix - B List of Formal Intervenors  
Appendix - C Summary 2006 Cash Working Capital Requirement  
Appendix - D Conservation & Energy Efficiency Plan 2006 - Detailed  
Summary Table  
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1
1.0  
INTRODUCTION  
[1]  
This decision is further to a public hearing conducted by the Nova Scotia Utility and Review  
Board (the ABoard@) over 13 days between November 14, 2005 and December 2, 2005, in the matter  
of an application by Nova Scotia Power Incorporated (ANSPI@, the ACompany@, the AUtility@) for  
approval of revisions to its Rates, Charges and Regulations.  
[2]  
NSPI is a regulated public utility and is the successor to Nova Scotia Power  
Corporation, a Crown Corporation which was privatized in 1992. As of January 1, 1999,  
NSPI became the principal subsidiary of Nova Scotia Power Holdings Incorporated, now  
known as Emera Incorporated (AEmera@).  
[3]  
NSPI is engaged in the production and supply of electrical energy. It distributes electricity  
through a province-wide system and, as at December 31, 2004, served approximately 468,000  
customers, including six municipal electric utilities. Its revenues for the year 2004 were $935  
million and its total assets, as at December 31, 2004, were $3.1 billion.1  
[4]  
In its application, dated July 5, 2005, NSPI requested an increase in rates to meet its  
proposed revenue requirement. It has used its estimated expenses for 2006 as the test year for  
ratemaking purposes. The proposed rate increases result in an average overall increase of 14.7%  
across all above-the-line classes. On November 21, 2005, NSPI announced that it had reached an  
agreement with its supplier on pricing for natural gas under an existing long-term natural gas  
1Exhibit N-2, Appendix A  
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2
purchase agreement, lowering its 2006 fuel forecast by $22 million. According to a News Release  
issued by NSPI on that date, the agreement reduces the proposed average rate increase to  
approximately 13% (Undertaking U-43).  
[5]  
The public hearing was duly advertised in accordance with sections 64 and 86 of the Public  
Utilities Act, R.S.N.S. 1989, c. 380, as amended (the AAct@), which read as follows:  
Approval of schedule of rates and charges of utility  
64 (1) No public utility shall charge, demand, collect or receive any compensation for any  
service performed by it until such public utility has first submitted for the approval of  
the Board a schedule of rates, tolls and charges and has obtained the approval of  
the Board thereof.  
Filing with Board  
(2) The schedule of rates, tolls and charges so approved shall be filed with the Board  
and shall be the only lawful rates, tolls and charges of such public utility until altered,  
reduced or modified as provided in this Act. R.S., c. 380, s. 64.  
Notice of hearing of application for rate changes  
86  
Notice of the hearing of any application, for the approval of or providing for an  
increase or decrease in the rates, tolls and charges of any public utility, shall be  
given by advertisement in one or more newspapers published or circulating in the  
cities, towns or municipalities where such changes are sought, for three consecutive  
weekly insertions preceding the date of said hearing, unless otherwise ordered by  
the Board. R.S., c. 380, s. 86.  
[6]  
A total of 39 formal intervenors responded to NSPI=s application. A number of these parties  
(identified in Appendix B attached) were represented at the hearing by Counsel. The Nova Scotia  
Department of Energy (the AProvince@); the Consumer Advocate (the ACA@); Avon Valley  
Greenhouses Ltd. et al. (AAvon@), whose Counsel represented approximately 19 intervenors; Stora  
Enso Port Hawkesbury Limited and Bowater Mersey Paper Company Limited (ASEB@); Halifax  
Regional Municipality (AHRM@); Affordable Energy Coalition (AAEC@); Ecology Action Centre  
(AEAC@); Electricity Consumers Alliance of Nova Scotia (AECANS@); Canadian Manufacturers &  
Exporters (ACME@); GasWorks Energy Corp. (AGasWorks@); the Liberal and NDP Caucus offices;  
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3
Dr. Larry Hughes; and the Municipal Electric Utilities of Nova Scotia Co-operative (AMEUNSC@)  
all participated in the hearing. The Board also received numerous submissions from members of the  
public opposing NSPI=s application.  
[7]  
A significant part of NSPI=s evidence involves the cost of fuel, particularly imported coal, as  
well as the projected benefit potentially earned by NSPI on the resale of natural gas. NSPI filed this  
information on a confidential basis. The Board imposed the precedent, established in the 2002 rate  
case and applied again in the 2005 rate case, which provides access to this information only to those  
intervenors who agree to sign confidentiality undertakings.  
[8]  
As a result, certain testimony, undertakings, exhibits and transcripts are considered  
confidential and are accessible only to the Board and those parties who agreed to sign confidentiality  
undertakings. For the most part, redacted versions of this evidence are on the public record. In  
addition, certain of the hearing days relating to evidence on fuel were conducted on an in camera  
basis.  
[9]  
In its 2002 decision the Board stated that:  
While conducting in camera sessions is an unusual occurrence for the Board, it is not  
precluded by the Board=s regulatory rules. Indeed the rules contemplate information being  
filed in confidence and also provide for other parties to request its disclosure. The Board  
believes that its role as a regulator responsible for protecting the public interest requires it to  
issue a decision that is, in all respects, accessible to the public. The Board considers that it  
is unacceptable to issue two versions of a decision - one public and one confidential.  
Therefore, although the Board has carefully considered all of the evidence filed during this  
proceeding, including those parts which involve confidential information, the Board has  
chosen, in this decision, to avoid direct reference to confidential information.  
(Board Decision, October 23, 2002, p. 5)  
[10] As it did in the 2005 rate case, the Board continues to believe that this is the most appropriate  
manner in which to issue a decision in a case where a significant portion of the evidence is  
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4
confidential. Accordingly, to the extent possible, this decision will not refer directly to confidential  
information.  
[11] The Board wishes to acknowledge, with appreciation, the contribution and participation of  
the intervenors, NSPI and the public in this proceeding. The significant work of the parties, as well  
as the expert witnesses appearing at the hearing, assisted the Board considerably in this process. The  
Board has reviewed, analyzed and considered many thousands of pages of material in its decision-  
making process.  
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2.0  
BACKGROUND  
[12] NSPI is a vertically integrated, investor-owned, regulated public utility with a virtual  
monopoly on electricity service throughout the Province. It is the primary electricity supplier in  
Nova Scotia, providing over 95% of the electricity generation, transmission and distribution in the  
Province.2 The Board regulates NSPI in the public interest on a cost-of-service basis. The Act gives  
the Board broad regulatory oversight over public utilities and provides it with the authority to  
discharge its regulatory responsibilities. Some of the relevant statutory provisions are as follows:  
Supervision of utility by Board  
18  
The Board shall have the general supervision of all public utilities, and may make all  
necessary examinations and inquiries and keep itself informed as to the compliance  
by the said public utilities with the provisions of law and shall have the right to obtain  
from any public utility all information necessary to enable the Board to fulfil its duties.  
R.S., c. 380, s. 18.  
Form of books and records of utility  
27  
The Board may prescribe the forms of all books, accounts, papers and records  
required to be kept by any public utility and every public utility is required to keep and  
render its books, accounts, papers and records accurately and faithfully in the  
manner and form prescribed by the Board and to comply with all directions of the  
Board relating to such books, accounts, papers and records. R.S., c. 380, s. 27.  
Examination and audit of accounts  
29 (1) The Board may provide for the examination and audit of all accounts, and all items  
shall be allocated to the accounts in the manner prescribed by the Board.  
Authority to inspect books or records of utility  
(2)  
The agents, accountants or examiners employed by the Board shall have authority  
under the direction of the Board to inspect all and any books, accounts, papers or  
records and memoranda kept by any public utility. R.S., c. 380, s. 29.  
Power to determine value of property of utility  
30 (1) The Board may at any time, with the assistance of such engineers, accountants,  
valuators, counsel and others as it deems wise or advisable to employ, inquire into  
and determine the extent, condition and value of the whole or any portion of the  
property and assets of any public utility used and useful in furnishing, rendering or  
2Exhibit N-25, IR-2, p. 9  
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supplying a particular service to or for the public, as of a date to be fixed by the  
Board.  
Duty of utility to furnish information  
33 (1) Every public utility shall furnish to the Board from time to time, and as the Board may  
require, maps, profiles, contracts, reports of engineers and other documents, records  
and papers, or copies of any and all of the same in aid of any investigation and to  
determine the value of the property of such public utility, and every public utility shall  
co-operate with the Board in the work of the valuation of its property in such further  
particulars and to such extent as the Board may direct.  
Approval of improvement over $25,000  
35  
No public utility shall proceed with any new construction, improvements or  
betterments in or extensions or additions to its property used or useful in furnishing,  
rendering or supplying any service which requires the expenditure of more than  
twenty-five thousand dollars without first securing the approval thereof by the Board.  
R.S., c. 380, s. 35; 2001, c. 35, s. 30.  
Separate rate base for each service supplied  
42 (1) The Board shall fix and determine a separate rate base for each type or kind of  
service furnished, rendered or supplied to the public by a public utility.  
Factors considered in establishing rate base  
(2)  
In establishing a rate base the Board shall determine the value of the physical assets  
of the public utility in accordance with the provisions of this Act, including in such  
value the actual reasonable and necessary cost of labour and supervision up to and  
including gang foreman, and the Board may, in its discretion, make allowances for  
the following matters, and such other matters as the Board deems appropriate:  
(a)  
(b)  
necessary working capital;  
organization expenses to the extent of such sum as the public utility may  
establish to the satisfaction of the Board to have been reasonably and  
prudently expended out of capital account in respect of organization  
expenses as defined by the regulations of the Board;  
(c)  
construction overheads to the extent of such sum as the public utility may  
establish to the satisfaction of the Board to have been reasonably and  
prudently expended out of capital account in respect of engineering,  
superintendence, legal services, taxes and interest during construction, and  
like matters not included in the valuation of the physical assets;  
(d)  
(e)  
expenses of valuations to the extent of such sums as may have been  
expended in respect of a valuation by the Board and, with the approval of  
the Board, charged to capital account;  
costs in whole or in part of land acquired in reasonable anticipation of future  
requirements.  
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Amortization of organization and valuation expenses  
(3)  
The Board may direct that a public utility shall make such provision as to the Board  
seems proper for the amortization of the sums allowed in a rate base for organization  
expenses and expenses of valuations, and may direct that the sums required  
annually for such amortization shall be charged as an operating expense.  
Revision of rate base  
(4) The Board may from time to time revise any rate base making due allowance for  
extensions and additions to, improvements or alterations in and withdrawals or  
retirements from, the property and assets of the public utility.  
Existing rate base  
(5) Until a rate base is determined by the Board for any public utility pursuant to this  
Section, the present rate base for such public utility as from time to time revised or  
accepted by the Board shall continue in effect and shall be the rate base for such  
public utility, provided that the Board may direct that any such public utility shall  
make such provision as to the Board seems proper for the amortization of the sums  
allowed in such rate base for organization expenses, expenses of valuations or  
allowances not mentioned in subsection (2) and may direct that the sums required  
annually for such amortization shall be charged as an operating expense. R.S., c.  
380, s. 42; 1992, c. 8. s. 35.  
Orders by board respecting rates and charges of utility  
44  
The Board may make from time to time such orders as it deems just in respect to the  
tolls, rates and charges to be paid to any public utility for services rendered or  
facilities provided, and amend or rescind such orders or make new orders in  
substitution therefor. R.S., c. 380, s. 44.  
Amount utility entitled to earn annually  
45 (1) Every public utility shall be entitled to earn annually such return as the Board deems  
just and reasonable on the rate base as fixed and determined by the Board for each  
type or kind of service furnished, rendered or supplied by such public utility,  
provided, however, that where the Board by order requires a public utility to set aside  
annually any sum for or towards an amortization fund or other special reserve in  
respect of any service furnished, rendered or supplied, and does not in such order or  
in a subsequent order authorize such sum or any part thereof to be charged as an  
operating expense in connection with such service, such sum or part thereof shall be  
deducted from the amount which otherwise under this Section such public utility  
would be entitled to earn in respect of such service, and the net earnings from such  
service shall be reduced accordingly.  
Earnings are in addition to expenses and allowances  
(2)  
Such return shall be in addition to such expenses as the Board may allow as  
reasonable and prudent and properly chargeable to operating account, and to all just  
allowances made by the Board according to this Act and the rules and regulations of  
the Board. R.S., c. 380, s. 45.  
Power to compel compliance by utility  
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46  
The Board shall have power, after hearing and notice by order in writing, to require  
and compel every public utility to comply with the provisions of this Act and any  
municipal ordinance or regulation relating to said public utility, and to conform to the  
duties imposed upon it thereby by the provisions of its own charter, if any charter has  
or shall be granted it, provided, that nothing herein contained shall be held to relieve  
any public utility or its officers, agents or servants, from any punishment, fine,  
forfeiture or penalty for violation of any such law, ordinance, regulation or duty  
imposed by its charter, nor to limit, take away or restrict the jurisdiction of any court  
or other authority which now has or which may hereafter have power to impose any  
such punishment, fine, forfeiture or penalty. R.S., c. 380, s. 46.  
Duty to furnish information  
51 (1) Every public utility shall furnish to the Board all information required by it to carry into  
effect the provisions of this Act, and shall make specific answers to all specific  
questions submitted by the Board.  
Duty to furnish safe and adequate service  
52  
Every public utility is required to furnish service and facilities reasonably safe and  
adequate and in all respects just and reasonable. R.S., c. 380, s. 52.  
Approval for transfer of undertaking  
62  
Notwithstanding the provisions of any Act of the Legislature, no public utility shall  
sell, assign or transfer the whole of its undertaking or any part thereof to any person  
or corporation except with the approval of the Board first had and obtained. R.S., c.  
380, s. 62.  
Approval of schedule of rates and charges of utility  
64 (1) No public utility shall charge, demand, collect or receive any compensation for any  
service performed by it until such public utility has first submitted for the approval of  
the Board a schedule of rates, tolls and charges and has obtained the approval of  
the Board thereof.  
Filing with Board  
(2)  
The schedule of rates, tolls and charges so approved shall be filed with the Board  
and shall be the only lawful rates, tolls and charges of such public utility until altered,  
reduced or modified as provided in this Act. R.S., c. 380, s. 64.  
Equal rates and charges for similar services  
67 (1) All tolls, rates and charges shall always, under substantially similar circumstances  
and conditions in respect of service of the same description, be charged equally to all  
persons and at the same rate, and the Board may by regulation declare what shall  
constitute substantially similar circumstances and conditions.  
Contravention prohibited  
(2)  
The taking of tolls, rates and charges contrary to the provisions of this Section and  
the regulations made pursuant thereto is prohibited and declared unlawful. R.S., c.  
380, s. 67.  
[13] NSPI last filed an application for a general rate increase in June of 2004. The hearing was  
held between November 2004 and January 2005, and the Board=s decision was issued on March 31,  
Document : 112539  
9
2005. Certain findings in the 2005 rate decision, which are relevant to this case, can be summarized  
as follows:  
$
The Board reduced NSPI=s revenue requirement by $53,244,000 million  
(approximately $70 million considering tax impacts) for the 2005 test year,  
which resulted in an average rate increase of approximately 5.3% for above-  
the-line customers, with an estimated rate increase of approximately 6.1% for  
most of these customers, including domestic customers, effective April 1,  
2005. NSPI had proposed an average overall rate increase of 12.4% across  
all classes;  
$
$
The Board approved a 10.4% rate increase for all below-the-line customers,  
effective January 1, 2005;  
A settlement agreement proposed by NSPI was not approved, primarily due  
to the Board=s concerns that its acceptance would cause the significantly  
higher cost of fuel projected by NSPI to be deferred to the expense of  
ratepayers either in 2005 or in later years;  
$
$
$
The common equity ratio for ratemaking purposes was increased from 35%  
to 37.5%;  
The Board approved a return on equity at 9.55% for the purpose of setting  
rates, with the earnings range set at 9.30% to 9.80%;  
The Board directed NSPI to use a return on rate base methodology for its  
next rate application rather than its long-standing practice of determining the  
return on the equity portion of total capitalization;  
$
$
NSPI was found to be imprudent by the Board in its imported coal  
procurement practices by failing to address these issues quickly, or efficiently  
enough, following the 2002 rate decision, to adequately protect itself or its  
ratepayers. As a result, the Board directed that the cost of fuel and  
purchased power approved for the 2005 test year be reduced by $18 million  
to reflect this imprudency;  
NSPI was directed to promptly engage high level in-house expertise to lead  
the imported coal aspect of its fuel procurement process and to establish a  
more efficient and accountable decision-making structure with respect to fuel  
procurement;  
Document : 112539  
10  
$
$
Given the imprudence and inadequacies in NSPI=s fuel procurement  
practices, the Board determined it inappropriate to approve a fuel adjustment  
mechanism;  
The Board determined that s. 21 taxes should be deferred for 2005 and  
2006, and that they be amortized over an eight year period commencing in  
2007. This resulted in an actual reduction in NSPI=s 2005 revenue  
requirement of approximately $32.7 million;  
$
$
$
The proposed increases for miscellaneous charges were found to be too high  
and were limited by the Board to an increase equal to the average rate of  
increase for above-the-line rates, rounded to the nearest dollar;  
The Board determined that it does not have the statutory authority to approve  
a rate assistance program to help low-income customers meet their electricity  
costs;  
The Board directed NSPI to initiate a technical conference process, with  
interested parties and stakeholders, to pursue an improved and effective  
demand side management program.  
Document : 112539  
11  
3.0  
3.1  
FUEL ISSUES  
General Overview  
[14] In its Notice of Application and Direct Evidence, NSPI indicated that this rate case is  
substantially about 2006 fuel costs, and it indicated that A... As is the case with similar  
utilities throughout North America, Nova Scotia Power and its customers are facing  
increasing costs for solid fuels, natural gas and oil driven by high and volatile global energy  
markets@.3  
[15] NSPI pointed out that customer rates approved for 2005 are based on a fuel and purchased  
power budget of $359 million. It expects that the fuel expense for the 2006 test year will be $120  
million higher, for a total expected fuel and purchased power cost of $479 million. This amount is  
shown in Table 2, Appendix A of Exhibit N-2.  
[16] Given the magnitude of the projected increase in fuel costs and its impact on rates, all aspects  
of NSPI=s fuel procurement strategy, policies, procedures and cost estimates were subject to  
thorough scrutiny at the hearing.  
[17] The Liberty Consulting Group (ALiberty@) was engaged by Board Counsel and carried out a  
comprehensive review of NSPI=s fuel procurement strategy, policies, procedures and cost estimates,  
just as it had in connection with the previous rate application. In its Direct Evidence, Liberty sets  
out the key points in its evidence:  
3Exhibit N-1, p. 7  
Document : 112539  
12  
Fuel Forecasting  
!
Prices in the fuel market are cyclical, volatile, and  
difficult to predict with  
a
substantial degree of certainty.  
!
!
We continue to believe from the information made available that NSPI has chosen a  
near-term emission-requirements path of procuring and burning low sulfur coal from  
the international market in its generating stations.  
Fuel management strategies must recognize the unpredictable nature of the fuel  
markets.  
Fuel Management  
!
Fuel management encompasses all fuels for power generation, from the initial stages  
of planning, through development of strategies, procurement, fuel transportation,  
contract administration, and inventory management. Fuel management includes  
optimization evaluations of capital expenditures related to fuel use, and balancing  
fuel mixes among generating stations. It also requires the existence and use, in  
supporting fuel procurement decisions, of tools and models sufficient to allow sound  
consideration of the comparative costs of producing electrical energy at the bus-bar,  
consistent with reliability, environmental requirements, and legal considerations.  
NSPI has since the last case made substantial progress in addressing the fuel  
management weaknesses that we observed. A number of important challenges  
remain to be met, however, in satisfying itself and the Board that a full range of  
necessary capabilities exists.  
!
"
NSPI has significantly improved its Fuel Procurement Policies and  
Procedures, but there are still opportunities for improvement  
NSPI has significantly improved its fuel procurement portfolio strategy  
NSPI has made satisfactory progress in beginning  
to build its new fuel supply portfolio, but  
"
"
must continue to make commitments to  
bring about its intended results  
"
NSPI has made satisfactory  
progres  
s
in  
improvi  
ng the  
image it  
conveys  
to the  
coal  
supply  
market  
"
NSPI has satisfactorily resolved  
Liberty=  
s
organiz  
ation-  
structur  
e
Document : 112539  
13  
concern  
s
from  
the prior  
case  
"
"
NSPI has not sufficiently improved its procedures for fuel hedging  
NSPI does not appear to have the necessary procedures for the  
procurement of purchased power  
"
"
"
NSPI has not demonstrated a use of modeling in long-term coal supply  
analyses sufficient to evaluate fully such issues as fuel switching costs, or  
system generating unit changes, to comply with the lower SO2 cap  
NSPI has made some improvements in its fuel procurement model, but still  
cannot demonstrate that it is procuring fuels that will result in the lowest  
possible cost of electrical energy delivered to the bus-bar  
NSPI has not demonstrated a satisfactory contract administration system,  
that it has conducted the appropriate reviews of fuel procurement  
solicitations, or that the appropriate levels of management have reviewed  
and approved procurement decisions and commitments.  
2006 Fuel Cost Review  
!
!
Volatility in market prices for fuel used for electricity generation has continued and  
market prices have increased substantially since the last case.  
There is substantial reason to believe that this volatility will remain in the period  
during which NSPI will collect the rates to be established in this proceeding.  
!
!
Such volatility will create a substantial risk of over or under recovery of costs.  
That risk exists, no matter how sound the methods  
and the application of them to  
forecasts by NSPI.  
!
!
!
NSPI continues to suffer significant harm from past failure to adopt a robust portfolio  
strategy; not making sufficient long-term fuel commitments as far back as 2002 will  
continue to cause 2006 fuel costs to be higher than they should be.  
The magnitude of that harm has not diminished as much as might have been  
expected in light of NSPI=s change to a portfolio strategy, because 2006 fuel costs  
now appear to be significantly higher than they did during the last case.  
NSPI=s estimate of its 2006 solid fuel  
costs  
has  
turned  
out to  
be too  
high, as  
recent  
NSPI  
purchas  
es have  
reduced  
the  
amount  
of  
uncom  
mitted  
tonnage  
Document : 112539  
14  
s and at  
prices  
less  
than  
NSPI  
had  
estimat  
ed.  
!
!
[confidential]  
NSPI=s arrangement with affiliate Emera Energy Services (AEES@) for the sale of  
excess NSPI natural gas does not comport with standards of arm=s-length dealing  
with affiliates, good utility practice, or the Board=s 2002 decision addressing NSPI=s  
use of an affiliate for off-system gas sales.  
!
!
!
There were a number of anomalies in the solicitation process that NSPI used to  
select EES as the entity to purchase its excess natural gas; the documentation  
provided by NSPI indicates favoritism to EES.  
It would be reasonable for NSPI to sell its excess natural gas directly to a broader  
market [confidential]; at the least, NSPI should conduct arm=s-length, competitive  
solicitations for its gas sales.  
NSPI=s forecast of the total cost of its  
HFO  
require  
ments  
for 2006  
appears  
reasona  
ble;  
howeve  
r, this  
conclusi  
on must  
be  
qualified  
becaus  
e
of  
questio  
ns  
about  
affiliate  
purchas  
es and  
sales.  
!
There appear to have been substantial levels of sales and purchases of heavy fuel  
oil between Emera Fuels; the available documentation indicates that NSPI did not  
follow normal processes with respect to competitive purchasing practices and  
management approvals.  
(Exhibit N-97, pp. 5-9)  
[18] Based on its review, Liberty made the following recommendations:  
Planning  
Document : 112539  
15  
1.  
NSPI should immediately conduct an overall re-evaluation of its generating system to  
determine the optimum way of meeting new requirements for control of SO2  
emissions, as well as emissions of other pollutants of concern, from its generating  
plants. Such re-evaluation should incorporate a long-term view, not just the next  
several years. The recommended study should consider not only all fuel supply  
options, but also integration of fuel supply options with capital expenditures for  
alteration, modification, or expansion of its generating units, in order to achieve the  
lowest possible costs for generation of power, consistent with reliability,  
environmental concerns and legal considerations.  
Organization and Procedures  
2.  
3.  
4.  
NSPI should develop a more comprehensive set of fuel hedging policies and  
procedures that measure up to industry standards.  
NSPI should develop a complete set of procedures for the procurement of purchased  
power.  
NSPI should continue to refine its own internal spreadsheet model for fuel  
procurement in order to bring it to a level of sophistication that permits evaluation of  
fuel-supply options and procurement decision-making on the basis of procuring that  
mix of fuels that will result in producing the lowest possible cost of electrical energy  
delivered to the bus-bar.  
5.  
6.  
NSPI should continue to revise and refine the Fuel Procurement Policies and  
Procedures to resolve the concerns expressed in this testimony.  
NSPI should continue to tighten the controls on the overall fuel procurement process  
so that proper, readily available documentation demonstrates clearly that appropriate  
levels of senior management, including the Fuel Strategy Table, have reviewed and  
approved recommendations made to them regarding specific fuel procurement  
decisions.  
Fuel Supply Portfolio  
7.  
NSPI should continue to build the fuel supply portfolio so that the parameters  
currently set forth by NSPI in its Fuel Procurement Policies and Procedures are  
achieved by December 31, 2007.  
. . .  
Affiliates  
11.  
NSPI should immediately bid on a fully competitive and arm=s-length basis its sale of  
excess natural gas for a one-year term, and should arrange for and coordinate that  
bidding and the cancellation of the existing agreement with EES with all reasonable  
dispatch. No costs associated with the termination of the agreement with EES  
should be included in customer rates.  
12.  
NSPI should also promptly conduct a complete and objective study of the net  
economic and other impacts of establishing an in-house capability to perform this  
sale function. The study should take into account likely future gas purchases and  
internal use and it should quantify the differential economics of a full range of  
Document : 112539  
16  
options. It should be filed with the Board within six months, and NSPI should  
specifically seek Board approval of the approach it intends to use (e.g., asset  
management, internal function, operation by NSPI within/without Canadian markets)  
to sell excess gas after the expiration of the new one-year contract that we  
recommend be put out for competitive bid as promptly as possible.  
13.  
There needs to be a comprehensive audit of affiliate transactions directly and  
indirectly affecting NSPI fuel procurement, sales, and costs, in order to verify that  
such transactions are not adversely affecting utility fuel costs.  
(Exhibit N-97, pp. 9-12)  
[19] Fuel experts retained by SEB and Avon echoed some of the same concerns and criticisms as  
Liberty and added a few more of their own. As is readily apparent, therefore, there are several  
important fuel related issues which the Board must address.  
3.2  
Fuel Procurement Strategy  
3.2.1 Overview  
[20] As a result of the Board=s 2005 rate decision with respect to the 2005 rate application, NSPI  
has made a number of changes with respect to its fuel procurement strategy, policies and procedures.  
NSPI, in its Direct Evidence, sets out these changes:  
The Board made several findings and issued directives concerning fuel procurement. NSPI  
has been asked to file a report with the Board within six months of the 2005 decision  
Aoutlining the implementation of the changes@ directed by the Board. That report will be filed  
by September 30, 2005. Meanwhile, having listened to concerns of the Board and customers,  
NSPI has worked to:  
$ Reorganize its fuel procurement function so that there is a single individual  
responsible for both the commercial and strategic aspects of fuel procurement. The  
Director, Energy, Fuels & Risk Management has an extensive background with NSPI  
and brings valuable experience to this position. He reports to the General Manager,  
Power Production who in turn reports to the Chief Operating Officer of NSPI. This  
organizational structure provides more efficient and accountable decision-making  
with respect to fuel procurement.  
$ Engage the services of an executive recruitment firm, STM Associates of Salt Lake  
City, Utah to identify candidates with experience in international coal markets and  
Document : 112539  
17  
coal procurement for employment with NSPI to lead the imported coal supply aspect  
of the Company=s coal procurement. Presently NSPI is screening candidates and  
expects that the successful individual would be in the position by September of 2005.  
The selected candidate will report to the Director, Energy Fuels and Risk  
Management. In the interim, the fuel procurement strategy has been developed and  
is being executed with the ongoing assistance of Energy Ventures Analysis Inc. In  
addition to its work in developing the fuel procurement strategy, EVA independently  
evaluates all solid fuel supply bids and participates on the Fuel Strategy Table.  
$ Revise its Policies and Procedures Manual to incorporate both specific comments  
and general concerns identified by the Board and other intervenors during the 2005  
rate proceeding including:  
N Revising its policy statements regarding objectives to more clearly indicate  
NSPI=s commitment to a portfolio strategy and to the evaluation of  
purchased fuels based upon a quality adjusted valuation on a system-wide  
basis; and  
N Defining a detailed portfolio strategy.  
$ Commit to further expanding its procurement portfolio to include multi-year  
commitments for low sulphur coal imports. To that end, NSPI solicited the market for  
multi-year offers in January and April 2005....  
$ Reconstitute its Fuel Strategy Table so that the Vice President, Emera Energy  
Services no longer participates. This will address concerns related to potential  
conflicts of interest between Emera and NSPI.  
. . .  
(Exhibit N-1, pp. 43-44)  
[21] The issue is whether the changes described by NSPI, adequately address the problems  
identified in the 2005 rate decision.  
3.2.2 Submissions - NSPI  
Document : 112539  
18  
[22] NSPI states that its objective, with respect to its Fuel Procurement Strategy, A... is to procure  
and manage a reliable and competitively-priced supply of fuel for its generation fleet consistent with  
regulatory and environmental requirements. This objective incorporates NSPI=s use of renewable  
energy such as hydro, wind, tidal, biomass as well as demand side management.@ It goes on to state  
that it will achieve this objective with A... first, a solid fuels procurement portfolio that consists of a  
combination of long and medium term agreements that collectively account for between 70 to 80  
percent of its annual solid fuel procurement and, second, a HFO and natural gas procurement  
strategy that allows NSPI to maximize the value of its long-term purchase contract for natural gas by  
consuming or selling the natural gas (and buying HFO) when it is economic to do so. NSPI further  
intends to complement its physical portfolio of fuels with appropriate financial hedges that are  
currently available or might become available in the future.@4  
[23] For purposes of its portfolio strategy, NSPI defines short-term agreements as being for one  
year or less; medium-term as being between one and four years; and long-term as being greater than  
four years.5  
[24] NSPI indicates in its Direct Evidence that it plans to continue to expand and refine its  
portfolio to:  
$
Provide a reliable source of competitively-priced fuels to the NSPI  
generating fleet that meet regulatory and environmental requirements;  
$
Maintain a portfolio of long, medium, and short-term agreements that  
provide for supply and supplier diversification with credit worthy  
counter-parties;  
4Exhibit N-1, pp. 44-45  
5Exhibit N-1, p. 45  
Document : 112539  
19  
$
$
$
$
Manage market volatility through agreements with staggered expiration  
dates, volume options, and varied pricing mechanisms;  
Maximize competition among suppliers by qualifying as many sources as  
possible;  
Buy Nova Scotia coal should competitive supplies of suitable quality be  
available; and  
Review commitments on an on-going basis.  
(Exhibit N-1, p. 47)  
[25] In a response to an Information Request from the Province, NSPI stated:  
NSPI moved quickly to implement the Board=s directives regarding fuel procurement. Since  
the 2005 Rate Decision received by NSPI on March 31, 2005, NSPI has made the following  
changes:  
$
Mr. Todd Sattler, VP Energy Services, ceased to participate in NSPI=s Fuel  
Strategy Table immediately on receipt of the Board=s decision. Also, Mr.  
Chris Huskilson no longer participates in the FST as of August, 2005.  
$
Mr. Mark Sidebottom was appointed to the position of Director, Energy,  
Fuels, and Risk Management. Within this role, Mr. Sidebottom takes on  
responsibility for both the strategic and commercial aspects of fuel  
procurement, ensuring that a single person is accountable for both.  
$
$
NSPI has established a more efficient and accountable decision-making  
structure.  
The Fuel Procurement Policies and Procedures Manual has been revised to  
address the Board=s directives from the 2005 Rate Case Decision, as well  
as the preferences expressed by customers. The Manual reflects the  
intention to reduce fuel price volatility and develop a portfolio with increased  
long and medium-term contracts, and  
$
NSPI has been working diligently to recruit high level in-house expertise to  
lead the imported coal supply aspect of its fuel procurement process, and  
with the assistance of a world-wide executive recruiter the process is  
nearing its final stages.  
(Exhibit N-72, NSDOE IR-91, Attachment 1, p. 24)  
Document : 112539  
20  
[26] In its Rebuttal Evidence filed with the Board on November 8, 2005, NSPI requested Board  
approval of the Fuel Procurement Strategy:  
In the short period since the end of the last rate case, NSPI has worked expeditiously to  
update its policies and procedures manual in order to respond to the concerns of the Board  
and customers.  
In general, the revised policies and procedures manual along with the restated procurement  
policy has received favourable reviews. Remaining areas of concern to Liberty are the  
hedging policy, and documentation. NSPI commits to further refining its hedging policies and  
procedures in concert with Liberty or alone as the Board sees fit and to providing whatever  
procurement documentation the Board determines is appropriate.  
NSPI requests an endorsement from the Board of the procurement policies and procedures  
as set out in the Manual filed with the Board in September.  
(Exhibit N-153, pp. 52-53)  
[27] In its Closing Argument, NSPI requests that the Board approve its Fuel Procurement Policies  
and Procedures Manual, and that the Board confirm that the strategy is being appropriately  
implemented.  
3.2.3 Submissions - Liberty and Intervenors  
Liberty  
[28] With respect to NSPI=s fuel procurement strategy, Liberty=s Direct Evidence stated that:  
NSPI has made significant, positive change to its fuel portfolio strategy. The new strategy is  
clear, does away with the limitation of contract lengths, and provides for longer term contracts  
with staggered expiration dates. The new approach eliminates the central theme of the old,  
speculative strategy, which was to stay close to the market, which we saw as a euphemism  
for spot purchases. The essential points of the new strategy are that NSPI will seek to:  
!
Maintain a portfolio of long-, medium-, and short-term agreements that  
provide for supply and supplier diversification with credit-worthy  
counterparties  
!
Reduce the effects of market volatility through agreements with staggered  
expiration dates, volume options, and varied pricing mechanisms  
Document : 112539  
21  
!
Maximize competition among suppliers by qualifying as many reliable,  
creditworthy, and geographically diverse sources as possible  
!
!
Buy Nova Scotia fuels, if available, based on price and quality  
Review commitments in order to determine whether renegotiations would be  
appropriate in the context of a changed market  
!
Build relationships with suppliers and counterparties based on credible  
performance  
. . .  
The exact components of the portfolio may vary over time in response to the market and  
other events. NSPI has already begun to build its solid fuel portfolio, and states that it desires  
to achieve its target portfolio percentages over the next 24 months. NSPI recognizes that this  
schedule may need to be extended, should there be limited supplier interest in longer-term  
agreements.  
NSPI=s new strategy is reasonable, and responds well to Liberty=s recommendations in the  
prior case. We also recognize that a portfolio cannot be built instantly, but will take time to  
assemble, cautioning that the issue of time lag begs the question of when the construction of  
such a portfolio should have begun.  
NSPI=s April 2005 solicitation sought [confidential] tonnes per year of long-term low-sulfur  
coal supply through 2008. NSPI recognized this solicitation as its first attempt to add a long-  
term solid fuel supply contract to its portfolio, in response to the Board=s March 2005  
decision. NSPI properly handled the solicitation, including a sufficient number of qualified  
potential suppliers, conducting bid evaluations, and making a decision that appears sound  
from the information that NSPI provided. NSPI procured the least-cost supply offered. This  
procurement was the only long-term solid-fuel supply agreement entered during the  
2004/2005 period, but NSIP[sic] did make shorter term purchases.  
Liberty did find, however, that the documentation supporting this decision failed to  
demonstrate approvals by the required level of management. The documents contained a  
page representing decisions of the Fuel Strategy Table and showing its approval. The  
documentation, however, was not in the form of official minutes of the Fuel Strategy Table,  
and did not contain any formal signatures authorizing the procurement. Liberty found the  
same deficiency in the majority of solicitations that NSPI conducted in 2004 and 2005. In no  
case were formal minutes of the Fuel Strategy Table included in what NSPI provided in  
response to Liberty=s request for procurement documents.  
The solid-fuel procurement commitments that NSPI has now made move it in the proper  
direction in increasing the percentage of supply from long-term contracts. The following table  
demonstrates the current solid fuel percentages (bases [sic] on 2005 tonnages) compared to  
the target solid fuel percentages. NSPI finds itself presently below target for long- and  
medium-term solid fuel contracts. However, we believe that its pace is reasonable, again  
subject to the concern about when NSPI began to implement this approach.  
. . .  
NSPI has established an appropriate fuel supply portfolio strategy, and has taken substantial  
efforts in building a portfolio that corresponds to it. The short time since the decision in the  
prior case addressing assembly of this new portfolio makes understandable that the portfolio  
Document : 112539  
22  
is not yet fully assembled. NSPI has stated that it intends to complete assembly of the  
desired portfolio in approximately 24 months; Liberty feels that every effort should be made to  
accomplish this objective.  
. . .  
NSPI has acted effectively and timely in developing and implementing its new portfolio  
strategy. The strategy appropriately responds to Liberty=s recommendations from the prior  
case and includes an appropriately defined mix of long-term, mid-term, and short-term fuel  
contracts. NSPI=s implementation of this strategy is acceptable, considering the time  
available since the Board=s decision from the prior case in March 2005.  
(Exhibit N-97, pp. 29-32 and p. 35)  
[29] With respect to NSPI=s fuel procurement policies and procedures, Liberty expressed  
concerns about the lack of management approvals concerning total tonnages to be acquired for the  
2006 commitment, and concluded that there is a lack of Aproper contract administration systems@ at  
NSPI.6  
[30] Liberty=s overall conclusions with respect to coal procurement and supply in 2005 and  
beyond are as follows:  
... We found that NSPI has improved its solicitations, and that it has corrected the RFP  
language concerns we had observed in the last case. NSPI=s solicitations have become  
more precise in communicating what NSPI actually wants in terms of tonnages and years of  
delivery. These improvements respond well to concerns that Liberty expressed in the last  
case.  
Liberty requested that NSPI provide the detailed evaluations associated with solicitations; in  
many cases it provided only those performed by EVA. Liberty realizes that NSPI is in a  
transition period, but believes that NSPI must move in the immediate future to develop and  
use the capability to conduct such evaluations with internal resources. Liberty believes that  
NSPI should make such internal evaluations the norm as soon as its new Senior Manager  
Solid Fuels is on-board and up to speed. Liberty emphasizes that its concern in this respect is  
administrative and not substantive. Our review of the bids disclosed no reason to conclude  
that NSPI failed to make a sound decision on which bidder to select.  
We emphasize, however, that attention to detail is essential to maintaining good performance  
in the long run. Our experience demonstrates that there is a point, which is hard to define  
objectively, at which the degree of inattention to administrative and procedural matters  
6Exhibit N-97, p. 44  
Document : 112539  
23  
becomes great enough to create concerns about the quality of substantive decisions and job  
performance.  
We observed a number of other cases that fall into this category. Liberty requested that NSPI  
provide documentation reflecting the securing of management approvals necessary for  
procurement. NSPI provided only sketchy and incomplete information in response. Most  
procurements included a ARecord of Decision@ from the Fuel Strategy Table, but in no case  
did Liberty find minutes of Fuel Strategy meetings, or NSPI management signatures  
indicating approval to proceed with commitments to suppliers. Most files contained copies of  
commitment letters signed by the NSPI Solid Fuels Commercial Manager or the Solid Fuels  
Operation Manager. The authority of these individuals, however, does not extend to the  
commitments as large as those for which they signed, absent written documentation with  
accompanying signatures from upper management.  
Typically, Liberty finds that utilities provide copies of procurement documentation approvals  
containing actual signatures of management, and of management committee personnel,  
indicating that, in logical sequence, management has seen, reviewed, and approved the  
evaluations and recommendations that led to the actual commitment of procurement from any  
given fuel supplier.  
(Exhibit N-97, pp. 44-46)  
[31] Liberty also examined NSPI=s procurements of purchased power, fuel oil, and natural gas.  
With respect to purchased power, Liberty indicated that the forecasted power purchases for 2005 and  
2006 were not under contract. NSPI makes purchases on an hourly basis as needed to supplement  
the most economic running of its generation fleet. Liberty expressed concern that NSPI A...does not  
appear to have any procedures governing the procurement of purchased power.@7 Without such  
procedures, Liberty is not able to determine whether or not the procurement of purchased power is  
being managed and controlled effectively.  
7Exhibit N-97, p. 50  
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[32] With respect to fuel oil and natural gas, Liberty stated that, as a share of the generation fuels  
mix, its use is expected to rise from 16.4% in 2004 to 17.8% in 2006. Liberty indicated that from  
2000 to late 2003, NSPI A...alternated between HFO and gas in the Tufts Cove steam units,  
depending on the delivered cost of HFO relative to the proceeds of selling the gas into the U.S.  
market. Since November 2002, however, the proceeds from selling the gas have been high enough  
to justify regular sale of gas and HFO burning at Tufts Cove.@8  
[33] With respect to NSPI=s Fuel Procurement Policies and Procedures Manual, according to  
Liberty, NSPI has made significant changes and has shown a solid commitment to improvement.  
However, Liberty expressed concern that A...it has taken longer than it should have to make changes.  
Moreover ... the lateness in making the changes make it impossible to determine how well they will  
be implemented....Only the passage of time under them, which has not yet happened, will allow  
insight affecting that question.@9  
[34] Liberty indicated that its major concerns in the last rate case concerning fuel procurement  
and the portfolio strategy have now been satisfactorily resolved with the new procedures. However,  
it stated that there are five areas not yet fully resolved by the new procedures, and these are:  
!
!
!
!
No indications of responsibility for preparation of management reports  
Continued frequent solicitations for low-sulfur import coals  
No indication of supplier performance measures that are important  
Improved, but still insufficient procedures on hedging  
8Exhibit N-97, p. 52  
9Exhibit N-97, pp. 89-90  
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!
Problematic procedures on coal inventory measurement  
(Exhibit N-97, p. 90)  
[35] Liberty also expresses concern that NSPI will use long-term solicitations to obtain coal  
pricing information rather than to seriously undertake actual fuel procurement, and the solicitations  
may be issued too frequently. Such solicitations may send the wrong message to potential fuel  
suppliers who A...will lose interest in submitting prices when they begin to suspect lack of intent to  
enter commitments....@10  
SEB  
[36] SEB, in its Closing Argument, states the following concerning the Fuel Procurement Policies  
and Procedures Manual:  
It became apparent during the proceeding that NSPI is seeking to have the Board approve its  
Fuel Procurement Policies and Procedures Manual (the AManual@) (Ex. N-167) as filed on  
September 14, 2005. Furthermore, in particular NSPI is seeking to have its Fuel  
Procurement Strategy set out at Section 1.2 of the Manual approved by the Board.  
SEB respectfully submits that this is inappropriate at this time, and would essentially be  
providing NSPI with a Ablank cheque@ with respect to fuel procurement. In particular, as  
NSPI has yet to hire the high level in-house expertise which the Board ordered in its 2005  
Decision, whoever may eventually fill that role has had no input into the Manual or the  
Strategy contained in the Manual.  
If the Board grants NSPI the approval it is requesting, it appears that NSPI would then argue  
in all future rate proceedings that as long as it was within the parameters of the portfolio  
strategy set out in the Manual, its procurement decisions would not be subject to challenge.  
NSPI has simply not demonstrated to date that it can be given such latitude.  
. . .  
10Exhibit N-97, p. 91  
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Although both Mr. Marston and Mr. Gubbins concede that in the long term and rationally  
applied, NSPI=s portfolio approach is a reasonable step towards building a prudent fuel  
procurement strategy, the evidence of neither suggests that NSPI is yet near this stage.  
Further, the continuing lack of in-house expertise with respect to solid fuel procurement  
strongly mitigates against the Board granting any approvals with respect to the Manual or  
NSPI=s proposed Strategy at this time.  
(SEB, Final Confidential Fuel Related Argument, pp. 56-57)  
Avon  
[37] Avon, in its Closing Submission, refers to Dr. Manfred Raschke=s, of International Strategic  
Information Services, criticism of the lack of transparency of the decision-making process  
concerning the fuel procurement procedures, and stated the following:  
At no time did NSPI produce Minutes of the FST meetings or NSPI management signatures  
indicating approval to proceed with commitments to suppliers. Instead, there are memos  
from EVA evaluating procurements and in certain circumstances Aa record of decision@.  
However, even the EVA records demonstrate a certain casual approach to record keeping  
and it is unclear whether the memos had been received, reviewed and considered before or  
after the FST meeting where the dates do not correspond with procurements and decisions.  
There continues to be an absence of experience in international coal procurement on the  
FST. NSPI has been diligent in keeping the Board and Intervenors updated with respect to  
its efforts to retain in-house expertise. We offered as a suggestion during the course of the  
hearing that with a continued lack of success in this regard, other options may be considered  
such as secondment of an individual within NSPI to another organization where he or she  
could Aapprentice@ the trade. We also encourage NSPI to identify and address any barriers  
to retaining an expert in-house.  
NSPI is seeking the Board=s endorsement of its Fuel Procurement Policies and Procedures  
Manual. Whether or not the Board chooses to approve the particular document, it is clear  
that judgment is required at every step of implementation of the policy B the timing for  
tenders, the volumes to be tendered, and the make up of the fuel mix. This was conceded in  
cross-examination of Mr. Tedesco.  
(Avon, Redacted Closing Submission, p. 22)  
[38] In concluding, Avon stated that:  
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With respect to NSPI=s Fuel Procurement Policies and Procedures, NSPI should be directed  
to improve upon its procedures for documenting decisions and recommendations and it  
should continue with its efforts to retain in-house expertise or develop expertise through  
secondment or other means.  
(Avon, Redacted Closing Submission, pp. 59-60)  
[39] Avon, in its Rebuttal Submission, went a step further and submitted that the Fuel  
Procurement Policies and Procedures Manual should not be approved.  
[40] Avon stated that:  
NSPI is looking for specific approval of its Fuel Procurement Policies and Procedures  
Manual. In their pre-filed evidence, Messrs. Antonuk, Spangenberg and Adger discussed  
their review of the revised Fuel Procurement Policies and Procedures Manual as filed on  
September 19, 2005. This Board will recall Liberty=s testimony in the prior case and its  
detailed recommendations with respect to NSPI=s fuel procurement policies. It is evident that  
NSPI has made strides in establishing its Manual and developing a portfolio approach,  
however deficiencies remain.  
Liberty stated with respect to the new Manual:  
Liberty=s testimony in the prior case listed 19 specific deficiencies in fuel  
procedures. The new procedures have satisfactorily resolved 14 of them.  
Our major concerns about objectives of fuel procurement and portfolio  
strategy have been satisfactorily resolved in the new procedures. The five  
areas not fully resolved by the new procedures include:  
!
No indications of responsibility for preparation of  
management reports.  
!
!
!
!
Continued frequent solicitations for low sulphur import coals.  
No indication of supplier performance measures that are important.  
Improved, but still insufficient procedures on hedging.  
Problematic procedures on coal inventory measurement.  
Furthermore, as pointed out by the Liberty Group, while the adoption of policies and  
procedures is a good first start, what is more important is whether the policies are  
communicated and used with rigour. Because of the lateness in implementing the changes,  
neither Liberty nor the Board has been able to determine how NSPI will operate under its new  
Manual.  
We have pointed out in our submissions of December 14, 2005, our concerns with  
respect to the lack of transparency of the decision-making process, the inadequate  
documentation and the continued inability of NSPI to hire a senior fuel procurement manager  
with international coal market and coal procurement expertise.  
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We have concerns with respect to NSPI=s request for blanket approval of its Fuel  
Procurement Policies and Procedures Manual. First, approval at this time, is premature as  
NSPI is still on a learning curve in developing its approach to prudent fuel procurement.  
There remains work to be done, the most significant of which is the retention of a senior fuel  
procurement manager who will have views on the appropriate contents of NSPI=s Manual.  
Second, one can anticipate that this Manual, like many policies within NSPI, will be a living  
document. It would be inappropriate for the Board to Aapprove@ the Manual as a whole  
requiring it to be fixed until such time as NSPI or the Board brings it back for further review.  
We suggest that at this stage the Board may wish to give direction and guidance on the  
general approach embodied in the Manual, with a reaffirmation that NSPI remains  
responsible to exercise independent judgment on the implementation of the Manual and as  
always, its decision-making will be assessed on the standard of prudence.  
(Avon, Rebuttal Submission, pp. 1-3)  
Province  
[41] The Province, in its Closing Submission, noted that NSPI has made considerable efforts  
towards improving its fuel procurement practices. It referred to the fact that NSPI has significantly  
revised its Fuel Procurement Policies and Procedures Manual. The Province noted that Liberty also  
commented on the significant improvements that NSPI made in this area:  
Q.  
And if I might just interrupt, to be fair you have found that significant improvements  
have been made in many, if not most, of your recommendations from last time.  
A.  
(Antonuk) Yes, and based on that, and based on more subtle things, attitude,  
atmosphere, reading the transcripts, I would now say I am optimistic. I don=t know if  
the company saw the light because they=re good guys and girls or whether they just  
felt the pain from the B B and I don=t care, I don=t think it matters. I=ve definitely  
gone from kind of probably no sense of optimism, maybe not pessimism but no  
sense of optimism, to thinking that Aif they get this job filled, I think they=re going to  
get there, and I think they=re going to get there quickly.@ It=s B B that=s a fuzzy  
thing and you know, I can=t be very analytical about it, I think that=s the main B B  
you know, I like the portfolio but the main thing I think is different from last year is  
that I do have that sense that they=re going to get there now, and they=re going to  
get there at a pace that B B you know, we always want good things to happen  
sooner, but I think they=re going to get there at a pace that=s going to work if they  
can, you know, get over this problem with finding the right person.  
(Transcript, November 29, 2005, pp. 2443-2444)  
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[42] The Province notes that there are two significant areas where improvement is required. The  
first was alluded to in Liberty expert witness John Antonuk=s comments above, relating to the hiring  
of a specialist in coal procurement, and the second one relates to the lack of transparency in  
decision-making. The Province stated:  
Regarding the employment of an experienced specialist in coal procurement matters,  
NSPI advised that it has retained a recruitment firm to assist it and has courted a few  
prospects. For various reasons, however, nothing has come of this. While NSPI is  
continuing with these efforts, it is also looking at other alternatives, such as retaining a  
company with considerable experience in coal acquisition.  
It will be important for NSPI to continue with these efforts and it seems likely that  
successfully completing this task will be one of the things that is necessary in order for NSPI  
to take its fuel procurement practices to the next level. This seems to be a key ingredient  
according to the portion of evidence from the Liberty fuel panel set out above.  
Given the difficulty it is having filling this necessary position at this point in time, NSPI  
should continue to build up internal expertise. It should also actively seek secondment  
opportunities or other training. When it deals with its fuel consultants, and once it does hire  
its specialist, NSPI should ensure that there are appropriate knowledge transfer and  
succession planning measures in place. This appears to be NSPI=s intention.  
The lack of transparency in NSPI=s fuel purchase decisions is troublesome. NSPI=s  
response to Liberty IR-20 provided copious amounts of documentation regarding various RFP  
processes undertaken by NSPI to procure fuel. More recently, the documentation involved  
with these processes has included evaluations done by Ms. Medine, although it would appear  
that sometimes these evaluations are in draft form and not completed until after Fuel Strategy  
Table meetings. The most significant concerns that were expressed during the hearing seem  
to centre around the lack of independent NSPI analysis on procurement decisions and the  
absence of detailed documentation relating to Fuel Strategy Table meetings and decisions.  
Instead, what appears is simply a Record of Decision, that simply notes the decision points  
that have been made without elaboration or justification.  
Dr. Rashke [sic] described NSPI=s decision-making process as Atotally obscure@.  
He characterized the fuel strategy table as a Ablack box@. ...  
. . .  
Other consultants share these concerns. Mr. Marston described the minutes of Fuel  
Strategy Table Meetings as Asparse at best@. In its prefiled evidence, Liberty also expressed  
concern about the lack of documentation surrounding NSPI=s decision-making processes:  
Q.  
What documentation formed the basis for this evaluation?  
A.  
Liberty IR-20 asked a number of questions related to NSPI=s fuel  
and fuel transportation procurement. Included were questions  
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relating to the RFP, vendor lists, vendor responses, NSPI analysis  
and evaluations, recommendations to management, evidence of  
proper management review and approval, copies of agreements,  
and delivery-tracking information necessary to confirm contract  
compliance. Our experience in examining many such files at other  
utilities led us to anticipate that the responses would provide  
substantial insight into the adequacy of NSPI=s decision-making  
processes.  
Q.  
A.  
Q.  
A.  
Did NSPI provide the requested information?  
Partly.  
What information was not provided?  
NSPI provided the information in five large, three-ring binders. In  
no case was the requested delivery tracking information provided.  
In many cases, it was not evident that the proper level of  
management had reviewed and approved the evaluations and  
recommendations made by NSPI staff or EVA. In most cases, the  
files did not contain evaluations and recommendations made by  
NSPI staff. Instead, it appears that NSPI relied on the evaluations  
and recommendations of EVA. It was therefore not possible to  
assess the nature and quality of the analysis and evaluation skills of  
NSPI staff.  
Liberty went on to note that the condition of the information that was provided by NSPI Adid  
not measure up to what Liberty is accustomed to seeing in the equivalent files of utilities that  
have sufficiently organized contract administration systems@. In addition to the foregoing,  
Liberty also expressed a concern that NSPI=s hedging policies and procedures were not  
sufficiently detailed in its Fuel Procurement Policies and Procedures Manual.  
The Province was pleased to note that, in its Rebuttal Evidence, NSPI has undertaken to  
continue its efforts to revise and develop its formal policies and procedures manual, and in  
particular, its offer to work with Liberty or alone as the Board sees fit to further refine its  
hedging policies and procedures, and to provide whatever procurement documentation the  
Board determines is appropriate. This issue requires follow-up, but NSPI seems determined  
to address the concerns that have been raised.  
(Province ,Confidential Closing Submission, pp. 11-14)  
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3.2.4 Findings  
[43] The Board has carefully reviewed the evidence pertaining to NSPI=s fuel  
procurement procedures and the Fuel Procurement Policies and Procedures Manual. The  
Board notes that Liberty stated in its Direct Evidence that NSPI has made significant and  
positive changes to its fuel portfolio strategy. Liberty indicated that the new strategy A... is  
reasonable, and responds well to Liberty=s recommendations in the prior case, ... and  
includes an appropriately defined mix of long-term, mid-term, and short-term fuel  
contracts.@11  
[44] The Board recognizes the effort expended by NSPI in implementing many improvements in  
its fuel procurement procedures, and in the Manual, in the relatively short period of time which has  
elapsed since the Board=s March 31, 2005 decision. The Board is pleased with the dedication shown  
by NSPI towards improving its procedures in this very important area of NSPI=s operations. The  
Board also notes that there appears to be general acceptance by the intervenors that NSPI has made  
significant improvements in the fuel procurement area.  
[45] However, Liberty also observes that while NSPI had satisfactorily dealt with many of the  
specific deficiencies in fuel procurement procedures, which Liberty commented on in the last rate  
case, a number of deficiencies still remain, including those set out in paragraph 34 above.  
[46] Liberty, during questioning by the Board, stated that while the new Procedures Manual goes  
some distance in addressing Liberty=s concerns, it does not fully resolve them. Liberty stated:  
11Exhibit N-97, pp. 30 and 35  
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We=d like to see the procedures better, we=d like to see the controls tighter, but  
we=d also and, I think more urgently, like to see the person put in place and ... if it=s the right  
kind of person, we expect he or she is going to say AWe need to tighten up these procedures.  
We need to have more transparency with how we make our decisions on specific  
procurement.@  
(Transcript, November 29, 2005, p. 2416)  
[47] The Board notes that SEB, in its Final Confidential Fuel Related Argument, has  
recommended against approving the Manual at this time. One of the reasons advanced by SEB for  
not approving the Manual now is that A... NSPI has yet to hire the high level in-house expertise  
which the Board ordered in its 2005 rate decision, whoever may eventually fill that role has had no  
input into the Manual or the Strategy contained in the Manual.@12  
[48] Avon, in its Rebuttal Submission, also argued against providing blanket approval of the  
Manual at this time. Avon states that:  
... approval at this time is premature as NSPI is still on a learning curve in developing its  
approach to prudent fuel procurement. There remains work to be done, the most significant  
of which is the retention of a senior fuel procurement manager who will have views on the  
appropriate contents of NSPI=s Manual ... It would be inappropriate for the Board to  
Aapprove@ the Manual as a whole requiring it to be fixed until such time as NSPI or the Board  
brings it back for further review. We suggest that at this stage the Board may wish to give  
general direction and guidance on the general approach embodied in the Manual, with a  
reaffirmation that NSPI remains responsible to exercise independent judgment on the  
implementation of the Manual and as always, its decision-making will be assessed on the  
standard of prudence.  
(Avon, Redacted Rebuttal Submission, pp. 2-3)  
[49] NSPI has requested that the Board approve its Fuel Procurement Policies and Procedures  
Manual, and confirm that the strategy is being appropriately implemented. While the Board is in  
12SEB, Confidential Fuel Related Argument, p. 56  
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general agreement with the Fuel Portfolio Strategy set out in Section 1.2 of the Manual, the Board is  
not prepared to approve the Manual at this time, nor is it able to confirm that the strategy is being  
appropriately implemented. The Board has concerns about the significant deficiencies noted and  
commented on by Liberty and other intervenors in this hearing. These deficiencies include a lack of  
managerial approvals of material fuel purchases, including coal, petcoke, and heavy fuel oil, a lack  
of adequate evaluations by NSPI staff of various solicitations, a lack of appropriate Fuel Strategy  
Table documentation surrounding its approval of purchases, a lack of adequate procedures  
surrounding the procurement of purchased power, and inadequate procedures surrounding the  
hedging function. Further, in the light of the lack of appropriate approvals, the Board expects that  
there will be a thorough review of the existing approval protocols set out in the Manual with a view  
to tightening them up considerably. There may be other aspects of the Manual which need to be  
strengthened. The Board agrees with Avon that more work is required on the Manual, and that the  
new fuel procurement manager may suggest significant refinements which ought to be made to the  
Manual.  
[50] The Board is pleased that NSPI, in its Redacted Rebuttal Evidence, has committed to  
working with Liberty to further refine and improve its hedging policies and procedures, and to  
provide whatever procurement documentation the Board recommends.  
[51] The Board directs that NSPI implement, as soon as possible, all the recommendations by  
Liberty set out in this decision, and that NSPI file a report by August 31, 2006, outlining the status  
of the recommendations which were implemented, and those recommendations, if any, which were  
not implemented. The Board further directs that NSPI liaise with Liberty in the implementation of  
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these recommendations, which are set out in section 3.0 above. The Board notes that there are other  
directives issued to NSPI by the Board with respect to the work performed by Liberty, and these  
directives are found elsewhere in this decision.  
[52] In the meantime, notwithstanding that the Manual is not finalized and has not received  
approval, and the Board has not approved the Fuel Portfolio Strategy, NSPI must proceed with the  
implementation of its proposed fuel strategy. The Board expects NSPI to use its judgment both with  
respect to the changes it proposes to the Manual, and with respect to the implementation of the fuel  
strategy.  
[53] In its March 31, 2005 decision, the Board directed NSPI to engage a fuel procurement expert  
with respect to coal acquisition. This has not occurred. While the Board understands that NSPI has  
been diligently working to identify and employ such an individual, the Board wishes to convey to  
NSPI its concern over the lack of progress in this very significant area of NSPI=s operations. The  
proposed expenditure for coal in the 2006 test year, as contained in Appendix A of Exhibit N-2, is  
$295.4 million, which is by far the largest of any other proposed expenditure for the 2006 test year.  
It is absolutely critical that NSPI obtain the necessary sophisticated knowledge in coal procurement  
procedures.  
[54] The Board notes that NSPI has been using the services of EVA, on a temporary basis,  
pending acquisition of the coal expert. While EVA appears to be highly regarded in the international  
coal community, this is only a short-term measure, and it does not, by itself, ensure the acquisition of  
the necessary knowledge and skills by NSPI staff.  
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[55] Accordingly, the Board directs NSPI to continue expeditiously with its efforts to obtain a  
solid fuel expert. Failing that, NSPI is directed to consider and evaluate other options which would  
permit it to acquire the necessary skills to enable it to acquire coal on a competitive basis in the  
international market. The Board notes that during the hearing other options were suggested. Avon,  
for example, suggested in its Closing Submission, that consideration could be given to the  
secondment of an NSPI individual to another organization to acquire the necessary expertise. NSPI  
is directed to file a quarterly status report with the Board concerning this matter, commencing April  
30, 2006. Further, the Board directs that NSPI liaise with Liberty with respect to its progress in  
finalizing this matter.  
3.3  
Carryover of Imprudency  
3.3.1 Overview  
[56] In its rate decision dated March 31, 2005, the Board adopted the standard for determining  
prudency as defined by the Illinois Commerce Commission:  
... prudence is that standard of care which a reasonable person would be expected to  
exercise under the same circumstances encountered by utility management at the time  
decisions had to be madeY.Hindsight is not applied in assessing prudenceY.A utility=s  
decision is prudent if it was within the range of decisions reasonable persons might have  
made. Y The prudence standard recognizes that reasonable persons can have honest  
differences of opinion without one or the other necessarily being imprudent.  
(Board Decision, March 31, 2005, p. 43)  
[57] In the same decision, the Board made the following comments in finding that NSPI=s  
imprudence in its fuel procurement should be set at $18 million for the 2005 test year:  
The Board has carefully considered the evidence heard with respect to NSPI=s fuel  
procurement strategy and actual practices. There is no question that, in the 2002 rate  
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decision, the Board stopped short of finding NSPI=s fuel procurement to be imprudent. The  
Board understood that with the closure of Devco, and the end of the majority of NSPI=s coal  
supply coming from domestic sources, NSPI had to begin purchasing much of its fuel supply  
in the international market. The Board believed that NSPI, at that time, was relatively  
inexperienced in international coal markets and that the Company should be provided with a  
fair opportunity to make the changes necessary, in both its organizational structure and in fuel  
procurement practices, to address this important change in its coal supply procurement.  
. . .  
The Board has carefully reviewed NSPI=s defense of its coal procurement strategy  
since 2002. As NSPI points out, it hired Ms. Medine as an expert in this area; it developed a  
Fuel Procurement and Procedures Manual which was completed in July of 2004; and it has  
complied with the Board=s 2002 directives to return the coal procurement function to NSPI  
from Emera. NSPI asserts that it has taken reasonable and necessary steps to improve fuel  
procurement. According to NSPI, the fact that it currently has no long-term imported coal  
supply contracts does not fairly represent its revised procurement strategy. As NSPI explains  
it, during the period of time in question, mid or long-term coal supply contracts were  
inadvisable, either because of limited interest on the part of suppliers or unduly high prices.  
The Board acknowledges that certain of NSPI=s fuel procurement processes in 2002  
have changed considerably since that time. In 2002, NSPI was relatively inexperienced in  
terms of importing coal. The Board=s findings as to whether NSPI=s coal procurement  
practices in 2002 were imprudent were based on whether the strategy and practices used by  
NSPI were reasonable and prudent under the circumstances. As noted earlier, at that time,  
the Board did not find NSPI=s coal procurement to be imprudent as it believed NSPI should  
be given a reasonable opportunity to react to the fairly abrupt end to its reliance on domestic  
coal supply. This Aopportunity@ should have involved NSPI quickly acquiring the necessary  
in-house expertise for imported coal purchasing and expediently revising its purchasing  
practices to reflect the new reality of the international coal market supply.  
It is clear that NSPI took several important steps toward this goal. In early 2003,  
NSPI engaged Ms. Medine as an external coal consultant and began to develop a Fuel  
Procurement and Procedures Manual. Ms. Medine=s advice regarding the need to have a  
mixed balance of short, mid and long-term coal supply did not change since her 2002  
analysis. Her evidence at this hearing is consistent with her earlier advice. What she could  
not confirm was whether NSPI had acted quickly and effectively enough to actually implement  
recommended and necessary improvements in its fuel procurement activity.  
. . .  
The Board has reviewed the case law cited by the intervenors and NSPI on the question of  
the acceptable legal standard for a finding of imprudency. As SEB notes, s. 45(2) of the Act  
identifies that expenses which the Board may allow a utility to charge must be A... reasonable  
and prudent and properly chargeable ...@. The Board agrees with Avon and SEB that, while  
expenses are generally presumed to be prudent, when questions are raised with respect to  
prudency, the burden falls to the utility to satisfy the regulator that its actions were prudent  
and reasonable.  
While the Board recognizes that the definition of imprudence varies somewhat  
among the jurisdictions cited, there are several fundamental principles which are common.  
These include:  
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$
$
$
Were the utility=s decisions reasonable in the context of information which  
was known (or should have been known) at the time?  
Did the utility act in a reasonable manner and use a reasonable standard of  
care in its decision-making process?  
The imprudency test should relate to the circumstances at the time in  
question and not to hindsight.  
While several cases were cited on this issue by the parties, NSPI referred in  
particular to a decision of the Illinois Commerce Commission noted earlier. Following a  
review of the cases, the Board finds that the definition of imprudence as set out by the Illinois  
Commerce Commision [sic] is a reasonable test to be applied in Nova Scotia.  
Accordingly, the Board has focused on NSPI=s performance with respect to fuel  
procurement on the basis of the circumstances confronting NSPI in late 2002 and 2003. In  
the context of that test, the Board believes the circumstances at the time are reflected in the  
2002 hearing and decision. NSPI faced a significant change in its coal supply. It lacked  
high-level in-house expertise in the international coal market. It defended allegations of  
imprudence in coal procurement in 2002 and, while the Board did not make a finding of  
imprudence, it categorized NSPI=s coal procurement as A... lacking in sophistication ...@ and  
A... sufficiently lax so as to undermine NSPI=s ability to ensure ... that coal was obtained at  
the lowest possible price...@.13 In terms of the process for decision-making used since 2002,  
it has been criticized by Liberty witnesses as lacking in efficiency and accountability. NSPI  
does not appear to have quickly retained high-level in-house expertise in the international  
coal market. It is compelling that all of the fuel experts, including Ms. Medine, confirmed that  
coal prices declined in late 2002 through to mid-to-late 2003. NSPI did not obtain a single  
long-term coal supply contract during this time.  
The issue, in the Board=s opinion, is not NSPI=s stated intention to improve its  
practices but the timeliness and effectiveness with which actual implementation of the new  
approach was achieved. NSPI, in the Board=s view, failed to address its imported coal  
procurement problems quickly or efficiently enough to adequately protect itself or its  
ratepayers. Had it done so expeditiously following the 2002 rate hearing, the Board is  
satisfied that, based on the evidence at this hearing, it was possible for NSPI to create  
a balanced portfolio of short, mid-term and long-term imported coal at reasonable  
prices. Instead, NSPI appears to have slowly implemented the necessary changes to its  
procurement practices. It remains unclear to the Board whether the corporate philosophy  
actually changed, and whether the procedures and practices recommended by Ms. Medine  
are yet fully implemented, particularly with respect to the need for long-term coal supply  
contracts which exceed terms of twenty-four months.  
There is no question that, following the directives issued in the Board=s 2002  
decision, NSPI had a number of changes to be implemented concerning fuel procurement. It  
is possible that, in its effort to comply with other Board directives, the necessary changes to  
its procurement strategy were not dealt with as urgently as should have been the case.  
However, the practical reality of the need for many of the changes ordered in the 2002  
13Board 2002 Rate Decision, October 23, 2002, pp. 27-28  
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38  
decision was that NSPI had inappropriately transferred core utility functions to Emera without  
the approval of the Board. To the extent that compliance with the Board=s 2002 directives  
may have had an impact on the alacrity with which NSPI implemented fuel procurement  
process changes in late 2002 and early 2003, any delay in this regard is attributable to the  
decisions made by the Utility and Emera. Any financial impact as a result of delay in  
implementing these changes, specifically with respect to the higher cost of imported coal in  
2005, should not be borne by ratepayers.  
NSPI now faces a spot market for coal supply that has spiked. Consequently, NSPI  
and its ratepayers are confronted with higher than necessary fuel costs. The Board finds that  
NSPI has been imprudent in its fuel procurement practice and, accordingly, it is not fair or  
reasonable to permit the total of these costs to be passed on to ratepayers. The Board  
wishes to make it clear that, in its view, this is not a reflection on the integrity or intentions of  
individuals, particularly those who were part of NSPI=s fuel decision-making process. It  
does, however, reflect a corporate philosophy which did not change with the urgency and  
purpose required in the circumstances. NSPI, as a result of its management decisions, now  
faces changing and higher market prices. It will pay higher coal prices because it is almost  
completely subject to the vagaries of the short-term market for imported coal.  
While the Board finds that NSPI has been imprudent in its fuel procurement practice,  
it does not believe that the approximately $30 million reduction, which was suggested by a  
number of the parties, is an appropriate amount.  
The primary reason the Board does not agree with the suggested $30 million  
reduction is the relatively limited period of time during which coal prices declined. Even if  
NSPI had acted as quickly as it should have to change its procurement strategy and build a  
balanced portfolio of short, mid and long-term contracts, it had, at best, several months to do  
so. Considering that part of this time would be required to implement the necessary changes,  
NSPI had a relatively short period of time to take advantage of the decline in imported coal  
prices.  
The Board believes that an $18 million reduction in fuel costs, rather than $30 million,  
strikes a reasonable balance on this issue... [Emphasis added]  
(Board Decision, March 31, 2005, pp. 46-49)  
[58] Liberty and many of the intervenors during the current hearing contend that the consequences  
of NSPI=s imprudence extend to the 2006 test year.  
3.3.2 Submissions - NSPI  
[59] In its Rebuttal Evidence, NSPI set out its views concerning the allegations of imprudence  
made against it by a number of the consultants in their pre-filed evidence.  
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39  
[60] NSPI indicated that the evidence of the intervenors and Liberty should have considered the  
high and volatile world prices ... Ain light of the expeditious and transparent manner in which the  
Company has responded to Board and customer concerns, including adopting a detailed fuel supply  
portfolio strategy.@14  
[61] NSPI quoted the following from Liberty=s Direct Evidence:  
NSPI has established an appropriate fuel supply portfolio strategy, and has taken substantial  
efforts in building a portfolio that corresponds to it. The short time since the decision in the  
prior case addressing assembly of this new portfolio makes understandable that the portfolio  
is not yet fully assembled. NSPI has stated that it intends to complete assembly of the  
desired portfolio in approximately 24 months; Liberty feels that every effort should be made to  
accomplish this objective.  
(Exhibit N-97, p. 32)  
14Exhibit N-153, p. 6  
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40  
[62] NSPI stated that three issues dominated the fuel-related evidence presented by the  
intervenors in this case, being NSPI=s forecast which it used to estimate the price of uncommitted  
tonnages, its long-term commitments, and the continuation of the 2005 disallowance concerning the  
imprudence factor.15  
[63] NSPI noted that several of the consultants engaged in the current hearing were of the view  
that there should be a continuation of the $18 million imprudence finding of the 2005 rate case, with  
the result that the test year fuel costs should be reduced by $18 million. NSPI pointed out that A...  
there is a misconception that the Company was penalized by $18 million. In fact, NSPI was harmed  
by almost three times that amount.@ NSPI reasoned that it had requested a fuel adjustment  
mechanism, which the Board refused, and NSPI estimates that A... it will experience a shortfall of  
approximately $50 million in comparison to actual fuel costs, only $18 million of which the Board  
found to be imprudent.@16  
[64] NSPI also stated in its Rebuttal Evidence that the Board did not specify how it calculated the  
$18 million imprudence disallowance in the 2005 rate case, and suggested that, in EVA=s  
experience, this was not the norm for regulatory bodies.  
[65] NSPI=s Rebuttal Evidence went on to state:  
15Exhibit N-153, pp. 9-10  
16Exhibit N-153, p. 18  
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41  
While the Board did not share how it derived the disallowance, the Board was quite clear in  
its opinion that it did not find NSPI to be imprudent for its failure to enter into contracts in  
2002. Paragraph 82 of its decision states:  
The Board acknowledges that certain of NSPI=s fuel procurement  
processes in 2002 have changed considerably since that time. In 2002,  
NSPI was relatively inexperienced in terms of importing coal. The Board=s  
findings as to whether NSPI=s coal procurement practices in 2002 were  
imprudent were based on whether the strategy and practices used by NSPI  
were reasonable and prudent under the circumstances. As noted earlier, at  
that time, the Board did not find NPSI=s coal procurement to be  
imprudent as it believed NSPI should be given a reasonable  
opportunity to react to the fairly abrupt end to its reliance on domestic  
coal supply. This Aopportunity@ should have involved NSPI quickly  
acquiring the necessary in-house expertise for imported coal purchasing and  
expediently revising its purchasing practices to reflect the new reality of the  
international coal market supply. [Emphasis added in original]  
In paragraph 96, the Board goes on to state:  
The primary reason the Board does not agree with the suggested $30  
million reduction is the relatively limited period of time during which coal  
prices declined. Even if NSPI had acted as quickly as it should have to  
change its procurement strategy and build a balanced portfolio of short, mid  
and long-term contracts, it had, at best several months to do so. Considering  
that part of this time would be required to implement the necessary changes,  
NSPI had a relatively short period of time to take advantage of the  
decline in imported coal prices. [Emphasis added in original]  
Based upon these findings, EVA estimates that the period of imprudence to be perhaps  
February through July of 2003 as shown below. EVA notes that during this period, NSPI  
purchased all of its 2004 requirements, ahead of schedule and at an enormous cost savings  
to NSPI ratepayers.  
(Exhibit N-153, pp. 19-20)  
[66] NSPI notes that Colin V. Gubbins, of the McCloskey Group; Nancy Brockway, of  
NBrockway & Assoc., a former US utility regulator and consumer advocate; Dr. Raschke and  
Liberty all concluded that the 2005 disallowance should be continued into the 2006 test year and, in  
some cases, be higher than the 2005 disallowance.  
[67] NSPI continued:  
Those parties recommending a continued or escalating adjustment all suggest that the Board  
found NSPI=s failure to commit to multi-year contract tonnages in 2002 and 2003 to be  
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42  
imprudent. While the Board is the ultimate arbiter of its finding, EVA found no evidence in the  
Board decision for that to be the case. In fact, as noted above, EVA finds [the] opposite to be  
true, i.e. the Board did not find NSPI was imprudent for failing to enter into multi-year  
agreement in 2002 and therefore any lingering impacts from such failure are not relevant to  
the current Application.  
The methodologies employed by the three consultants making this recommendation vary.  
(Exhibit N-153, pp. 20-21)  
[68] During cross-examination by Board Counsel, Emily Medine, a principal in the firm of  
Energy Ventures Analysis (AEVA@), and NSPI=s fuel expert, stated that she disagreed with the  
opinion of those experts who say there is a continuing adverse impact on 2006 results due to the  
imprudence of NSPI in not securing any long-term contracts for coal in late 2002 and 2003. Ms.  
Medine cited a number of reasons why she disagreed with the opinions of the other experts:  
N
Ms. Medine stated that she was not sure how the $18 million was calculated  
in 2005:  
...my experience in imprudence findings is that there=s  
generally a calculation and, therefore, we can look at the  
calculation and see whether it=s applicable to future years.  
My sense was that the disallowance was sort of not  
specifically tied to an event but to general concerns, and I  
think the company heard that and has responded. So I  
don=t see it tied to a specific event....  
(Transcript, November 28, 2005, p. 2194)  
N
Ms. Medine stated that with respect to the contracts, when a calculation is  
done A... you need to have some assumptions, and I don=t know what  
assumptions to use in figuring out whether to continue to go forward or not.@  
N
In addition, Ms. Medine explained that the way she read the 2005 decision,  
there was no particular finding of imprudence in 2002:  
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43  
... so using foregone opportunities for 2002 to calculate a new number did  
not seem appropriate to me. ... I didn=t find any particular activity in 2002  
that the Board found to be imprudent, so I have a hard time understanding  
how you go back to 2002 and look at foregone opportunities, which would  
have been a contract that the company could have entered, and calculating  
a number related to that....  
(Transcript, November 28, 2005, pp. 2194-2195)  
[69] The following exchange between Board Counsel and Ms. Medine is instructive:  
Q.  
And I'm not asking you to agree with the calculations made by any of those experts.  
My question to you really was more whether there is anything in your opinion which  
would lead to the conclusion that while contract supply for 2005 was available to  
NSPI in 2002 or 2003 that such supply was not available for 2006.  
A.  
The best evidence is what offers were available to the company, and as I said, the  
only offer in 2002 that had tonnage going through 2006 was the [confidential] offer  
and that was a relatively small tonnage in 2006.  
Q.  
A.  
And that was the one used by Dr. Raschke?  
Dr. Raschke in his evidence just did a calculation. It was only in his opening  
statement that he then reverted his evidence to a recommendation, but certainly in  
his evidence itself it was never a recommendation of a disallowance, he just did a  
calculation.  
Q.  
A.  
Is it your evidence that if NSPI had, I guess, called for RFPs for multi-year contracts  
in 2002 and 2003, proper ones, that they would not have been able to secure supply  
for 2006?  
We're simply moving into the world of hypothetical, which in my experience isn't a  
basis for disallowance. I mean, maybe, if, would have, could have, should have. I  
don't know the answer to it. I know that when we went out for multi-year we got some  
respondents that did give for three years, some that gave for one year, some that  
gave for two years. If you go back and force the market to respond to terms that you  
want, you know, in theory you should get at a number a bid, but we have no idea  
how much of a premium somebody would charge the company in this hypothetical  
world where we would have insisted that we go out and buy for five years or  
whatever number you'd like to come up with....  
Q.  
What is the difference between 2006 -- and this is what I want you to speak to -- the  
difference in that respect between 2006 and 2005?  
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44  
A.  
Well, as I said, I can't speak to what happened in 2005 because I don't understand  
how the number was derived. I think in 2006 we are three or four years out from  
2002 and we still could have done a multi-year agreement and the agreement would  
have expired by 2006. I think we're beyond any period of potential imprudence  
related to a decision or non-decision in 2002.  
(Transcript, November 28, 2005, pp. 2196-2199)  
[70] In its Reply to the Closing Argument, NSPI stated that the Board must decide whether the  
imprudence assessed by the Board in its 2005 decision continues to cause damage in 2006, and if so,  
what is the extent of the damage:  
... It is the submission of NSPI that, on the evidence, no damage continues into 2006. NSPI  
urges the Board to search carefully for the contract opportunity that was not accessed by the  
Company and to search carefully for the evidence that can be used to calculate the alleged  
ongoing loss. NSPI submits there is no such evidence. As such, this cannot be a  
mechanism to reduce an otherwise justified increase in cost recovery.  
It is simply not acceptable, in light of the general principles of ratemaking outlined above, to  
accept speculation, unproven assumptions, inferences or >leaps= as a basis to disallow  
millions of dollars of revenue to the Company.  
(NSPI, Redacted Reply to Closing Argument, p. 8)  
3.3.3 Submissions - Intervenors and Board Counsel Witnesses  
SEB  
[71] In his opening statement, Colin Gubbins, an expert witness appearing on behalf of SEB,  
stated that past imprudence in NSPI=s purchasing strategy has forced NSPI into buying coal at a  
time when the market for coal has been overheated. It is Mr. Gubbins= view that NSPI=s  
ratepayers should not have to pay for this imprudence.  
[72] Mr. Gubbins stated that, had NSPI put in place long-term contracts in 2002 and 2003, it  
could have saved $45.98 million in 2006. According to Mr. Gubbins, A...The main reason for this  
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45  
disparity is the significant gap that exists between the prices available in 2003 and the estimates  
provided by Hill and Associates.@17  
[73] Richard Marston, of Marston & Marston Inc., also appearing on behalf of SEB, in his Direct  
Evidence, stated that in implementing a strategy of staying close to the market, A...NSPI declined to  
enter into reasonably priced long-term coal agreements in 2002 and 2003 that would have removed  
significant fuel cost risk through at least 2006".18  
[74] SEB, in its Final Confidential Fuel Related Argument, stated that A... Each of Mr. Gubbins,  
Mr. Marston, the Liberty Group and Dr. Raschke have indicated that the failure of NSPI >to take  
advantage of the decline in imported coal prices= (2005 rate decision, para. 96) has had a continuing  
impact for NSPI=s 2006 forecast fuel costs....@19  
[75] SEB indicated that Mr. Gubbins has calculated the continuing impact of the prior imprudent  
behaviour to be $30.4 million with respect to the 2006 test year fuel costs. SEB stated that A... As  
Mr. Gubbins specifically noted, NSPI=s failure to enter into longer term contracts in late 2002/early  
17Exhibit N-179, p. 2  
18Exhibit N-90, pp. 6-7  
19SEB, Final Confidential Fuel Related Argument, p. 13  
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46  
2003 has an even more significant impact in 2006 than in 2005, due to the fact that NPSI [sic] has  
had to purchase coal at an even higher price to cover its 2006 commitments than its 2005  
commitments.@20  
[76] SEB took issue with NSPI=s comments in its Closing Argument that the Board A... was quite  
clear it did not find NSPI to be imprudent for any failure to enter into long-term contracts in 2002."  
It is SEB=s view that:  
... NSPI=s interpretation of the 2005 Decision appears strained at best. Because of the clear  
impact of the failure to have entered into a term arrangement in 2002/2003, NSPI is  
struggling to find an interpretation that would suggest their failure to act in the past has no  
impact on the present. The record is clear that this is simply not correct.  
(SEB Confidential Fuel Related Rebuttal Argument, p. 10)  
20SEB, Final Confidential Fuel Related Argument, p. 15  
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[77] SEB also took issue with NSPI=s assertion that the actual fuel disallowance in 2005 was  
much larger than the $18 million because the Board did not approve NSPI=s proposal for the fuel  
adjustment mechanism. According to SEB, the disallowance was $18 million, and the Board A... did  
not approve a fuel adjustment mechanism because it did not feel it was appropriate for NSPI at that  
time....@21  
Avon  
[78] In its Closing Submission, Avon stated that the experts and consultants dealing with the fuel  
issue all believe that the 2006 test year fuel costs are impacted in a negative manner by the past  
imprudence. Avon summarized the evidence with respect to the past imprudence as follows:  
... The Liberty Consultants recommended that NSPI=s fuel expense for the rate year 2006  
should be reduced Abecause of the continuing harm suffered from past failure to adopt a  
robust portfolio strategy after its decision not to install scrubbers in 2001 and the resulting  
missed opportunities to procure long-term fuel supplies in the past at more economical  
prices.@  
In its evidence, the Liberty Consulting Group prepared a calculation assuming that in 2002  
and onward NSPI had a portfolio strategy in place to secure the 3.5 million tonnes of solid  
fuel required in 2006 and that conformed to the strategy it is now describing in its current Fuel  
Procurement Policies and Procedures Manual. During the cross-examination of the Liberty  
Panel, it was acknowledged that the calculation did not account for the domestic coal contract  
with Nova Construction. Accordingly, Liberty recalculated its Exhibit LCG3 to summarize the  
2006 cost of not having a balanced coal supply portfolio to be $23,300,460.  
(Avon, Redacted Closing Submission, p. 3)  
[79] In commenting on Dr. Raschke=s calculation of an amount for imprudence, Avon stated that  
his approach was the most conservative, and he calculated imprudence by referring to a A... single  
21SEB, Final Confidential Fuel Related Rebuttal Argument, p. 11  
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48  
specific contract which was available to NSPI but not taken up to fulfill its uncommitted tonnage.@  
Avon quotes from Dr. Raschke, as follows:  
It is also important to remember that in 2006 NSPI=s fuel costs still reflect the mistakes it  
made in the past in its coal purchasing. While in April 2005 it entered into a long-term  
contract with[confidential] while the market was still at or near record highs, in May 6, 2002,  
it had received a very much lower offer ... which it turned down....  
(Avon, Redacted Closing Submission, p. 4)  
[80] Dr. Raschke calculated the imprudence to be $8.06 million.  
[81] In its Rebuttal Submission, Avon stated that there is unanimity among the experts that there  
is ample evidence to support an ongoing impact of past imprudence. Avon suggested that Liberty  
has A... offered a reasonable alternative for calculating the value of the disallowance, being  
appropriately conservative with respect to pricing and volumes. We submit a disallowance of $23.3  
million is appropriate.@22  
Province  
[82] The Province, in its Closing Submission, stated that it is necessary to determine if NSPI=s  
failings in late 2002 and early 2003 continue to have cost consequences for the 2006 test year, and if  
so, to what extent. The Province suggested that:  
When answering these questions, the Board should reflect upon the circumstances that  
prevailed during late 2002 and early 2003. In the circumstances of this case, the Province  
does not believe that it is, or was necessary for the Board to have linked a finding of  
imprudence to the failure of NSPI to enter into a specific contract based on an offer that it had  
in hand during the relevant time frame. This is because the issue is not only what offers had  
22Avon, Redacted Rebuttal Submission, p. 10  
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been made to NSPI at the time, but what offers might have been made had NSPI conducted  
itself appropriately. To a greater extent, the issue is one of lost opportunity.  
. . .  
The Province submits that given the Board=s past finding that Ait was possible for NSPI to  
create a balanced portfolio of short, mid-term and long-term imported coal at reasonable  
prices@ in late 2002 and early 2003, the benefit of low prices that should have been obtained  
at that time would still be influencing the budget in 2006....  
. . .  
Consultants retained by the Board, Stora Enso/Bowater, Avon Valley et al. and the Consumer  
Advocate all recommended continuing an imprudence disallowance into 2006. Mr. Gubbins  
noted that because the differential between coal prices in 2002/2003 and 2006 has widened,  
an imprudence allowance would be higher in 2006 than that awarded by the Board last year.  
He recommended disallowance in 2006 of approximately $46 million. Dr. Raschke uses less  
volumes in his calculations and recommends a disallowance in 2006 for past imprudence of  
$8.06 million. Ms. Brockway recommended maintaining the $18 million disallowance into  
2006. Liberty recommended a disallowance of $23,300,460.  
(Province, Confidential Closing Submission, pp. 5-7)  
[83] While the Province believes that it is important to recognize that NSPI has made significant  
improvements in its fuel procurement practices over the past few years, it noted that A... continuing  
the Board=s past imprudence finding into the 2006 rate case would not be a negative commentary on  
NSPI=s more recent fuel procurement activities, but an acknowledgment that its sins of the past are  
continuing to have cost consequences that should not be borne by ratepayers.@23  
[84] The Province did not suggest a specific amount for an imprudence disallowance, although it  
expressed the view that the Board ought to continue the imprudence finding into 2006 based upon  
the assessments by the various consultants. It also agreed with Dr. John Stutz, a regulatory expert  
and Vice President of the Tellus Institute, and retained by Board Counsel, who stated that A... if the  
Board determines that it is appropriate to maintain an imprudence allowance into 2006, then it would  
23Province, Confidential Closing Submission, para. 15  
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be beneficial to provide additional guidance on whether the circumstances leading to the Board=s  
past imprudence finding will continue to exert an influence on NSPI=s fuel budget beyond 2006. If  
so, it would be further advisable to define parameters on how the excessive costs in the fuel budget  
are to be assessed in future years.@24  
Liberty  
[85] In its Direct Evidence, Liberty indicated that NSPI is suffering significant harm from its past  
failure to adopt a portfolio strategy, and Liberty concluded that, as a result of NSPI=s failure to enter  
into long-term commitments as far back as 2002, 2006 fuel costs will be higher than they otherwise  
would have been.  
24Province, Confidential Closing Submission, para. 14  
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[86] Further, it expressed the view that, notwithstanding NSPI=s adoption of a portfolio strategy  
A... The magnitude of that harm has not diminished as much as might have been expected in light of  
NSPI=s change to a portfolio strategy, because 2006 fuel costs now appear to be significantly higher  
than they did during the last case.@25  
[87] Liberty concluded, in its Direct Evidence, that the fuel expense for the 2006 test year should  
be reduced by a total of $23,695,740 as a result of NSPI=s past failure to adopt a A... robust portfolio  
strategy ... and the resulting missed opportunities to procure long-term fuel supplies in the past at  
more economical prices@.26 Subsequently, Liberty reduced their imprudence disallowance to a total  
of $23,300,460.27  
Dr. John Stutz  
[88] Dr. Stutz was asked by the Board during his testimony whether he thought there should be a  
finding of imprudence to the extent that 2006 coal was not bought in earlier years when prices were  
lower. He replied as follows:  
... Let me say to begin that I think it=s a very thorny issue, so if you=ll permit me, I=m  
going to address it in three parts. So the first question is, should the coal have been bought  
earlier and in a fashion which is what we now call a portfolio approach. I believe you  
answered that question in your last decision. You said basically that should have been done.  
That was the basis for your finding of imprudence in the last case.  
Second question is, is there a continuing harm now from not doing that. And there I  
think we need you need to rely on experts. Liberty, who have been consistent proponents of  
25Exhibit N-97, p. 8  
26Exhibit N-97, p. 11  
27Undertaking U-64  
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52  
the portfolio approach, would tell you there is a continuing harm, and so all I can say is I=ve  
listened to all the evidence and I find what they have to say about that point reasonably  
persuasive, that is, that there is as a qualitative matter a continuing harm.  
Now we get to the real thick of it. Do we know how much harm is continuing. And,  
frankly, I think that=s a swamp. I think it requires a fair amount of assumption because you  
have to imagine what portfolio would have been put in place back at that time in order to  
assess the harm. Liberty has done that. The company has pointed out and, I would say, it=s  
a fair argument that there were numerous assumptions that underlie that calculation. I think  
the difficult area for the Board, it will have to exercise its judgement, in my view, is to decide  
whether and to what extent they can quantify that harm, either as Liberty has done it or by  
other means, to assess an imprudence penalty.  
So I think, just to recap, yes, there was imprudence back then. In my view, the  
experts have made a case that the harm continues. The key question is, can you get a  
number. And I think it will ultimately be a matter of your judgment.  
(Transcript, December 2, 2005, pp. 3589-3590)  
3.3.4 Findings  
[89] In its rate decision of March 31, 2005, the Board dealt extensively with the issue of  
imprudence. It explained why it had ruled, in its 2002 rate decision, that there was no imprudence,  
and why in the 2005 rate decision, that there was imprudence. Given the significance of these  
findings with respect to the issue now before the Board, the relevant sections from the 2005 rate  
decision are set out in section 3.3.1 above.  
[90] After considering the record, the Board accepts the evidence of those experts who are of the  
opinion that there is a continuing harm in 2006 as a result of NSPI=s failure to implement a portfolio  
strategy commencing in 2002. The Board is satisfied that, for the same reasons as the Board found  
in its decision of March 31, 2005, NSPI had an opportunity at that time to begin implementing an  
appropriate fuel procurement strategy. If NSPI had taken advantage of that opportunity as it should  
have done, it would have been able to obtain coal for 2006 at costs significantly less than those  
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which it now forecasts for the 2006 test year. The additional expense involved should not be borne  
by the ratepayers because it was imprudently incurred.  
[91] The question then becomes, how can these costs be determined or measured? The Board  
concurs with Dr. Stutz=s observation that this is something of a Aswamp@, which requires the  
exercise of judgment rather than the pretext of mathematical precision. The Province made a similar  
point in its Closing Submission:  
When answering these questions, the Board should reflect upon the circumstances that  
prevailed during late 2002 and early 2003. In the circumstances of this case, the Province  
does not believe that it is, or was necessary for the Board to have linked a finding of  
imprudence to the failure of NSPI to enter into a specific contract based on an offer that it had  
in hand during the relevant time frame. This is because the issue is not only what offers had  
been made to NSPI at the time, but what offers might have been made had NSPI conducted  
itself appropriately. To a great extent, the issue is one of lost opportunity.  
(Province, Redacted Closing Submissions, para. 7)  
[92] The Board notes that the imprudence estimates calculated by the fuel experts range  
from $8.1 million in the case of Dr. Raschke, to $23.3 million in the case of Liberty, and to  
$30.4 million in the case of Mr. Gubbins. Each expert has calculated a different figure  
using different methodologies and assumptions. There is no consensus among them as to  
the correct amount.  
[93] NSPI challenges some of the assumptions made by the experts. The difficulty in determining  
an appropriate amount for imprudence is the result of NSPI=s lack of activity, during the period  
commencing in 2002, when the Company should have been taking steps to implement a diversified  
portfolio of coal contracts, but failed to do so. On this issue, the Board concurs with the comments  
made by Mr. Antonuk of Liberty during the hearing:  
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54  
A.  
(Antonuk) First of all, I can=t - - we didn=t do our analysis based on saying the  
company had a duty to be prudent when the Board told it to be prudent. And the duty  
for a company to act prudently is an internal responsibility. So I think it would be  
wrong to suggest that somehow their only obligation is to respond to what you tell  
them to do and when you tell them to do it, because you don=t run the company day  
to day or even, in most cases, year to year. But here obviously rate cases are pretty  
frequent. So I guess I have trouble understanding why there is all this focus on when  
you told them what. From our perspective, we look at what we think reasonable  
management would have done under the circumstances if they were self-motivated  
to do the right thing rather than sort of just responding to what you told them. So I=ve  
read the transcripts, this is the first time I=ve seen this one, so that all leaves me cold  
when I hear AWell when did the Board tell you this? How long should you have had  
to respond to the Board?@ Our whole view of it is what should management have  
been doing on its own at the time. We believe that the trigger event for starting to  
look at long-term low-sulphur coal supplies was the analysis in July ---  
A.  
A.  
(Spangenberg) >02.  
(Antonuk) C yeah, and that should have gotten them started. The fact that they  
didn=t get started is why we don=t have what Ms. Medine and Mr. Connors were  
referring to as offers. We weren=t buying coal then. It=s certainly not our job to come  
in here and say - or our burden to come in here and say AWell we were trying to buy  
coal for NSPI and this is what we got offers for.@ Because that=s the level at which  
you have to have offers. You know, fuel offers are unique to time, unique to quantity,  
unique to delivery point. So the real issue here is the company, in our opinion, didn=t  
do what it should have done, therefore it didn=t have offers. What do we do? We=re  
not going to go and look at what some company in Arizona got offered for coal at that  
time frame because we=d argue that=s irrelevant. What we tried to do is say what=s  
the best information that the company got in response to what it did do.  
. . .  
And remember, what this all comes down to is not that Liberty failed to solicit coal in  
2002, it=s that the company did. So the lack of information is certainly not our fault.  
The lack of information is because they were not doing what they should have been  
doing. So what we=re trying to do is use the best information available to say what  
would have happened had they done that. And I look at N-216 and I say I think you  
have to take a pretty darn narrow view of the world to say that the company who  
submitted this was not going to be able to supply in 2006 the very same quantities  
that they were willing to offer in 2003 through 2005....  
(Transcript, November 29, 2005, pp. 2456-2459)  
[94] As noted in the evidence quoted above, the difficulty in assigning a reasonable disallowance  
for imprudence is the result of NSPI=s failure to take appropriate action to build a diversified  
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portfolio in a timely manner. In the end, the Board must determine what amount is reasonable in the  
circumstances.  
[95] In reviewing the specific recommendations for an imprudence disallowance, the Board  
considers that Mr. Gubbins= recommendation is on the high side, and he relied on more aggressive  
assumptions in his calculations than either of the other two experts. The Board believes that an  
imprudence disallowance in the mid-range between the amounts recommended by Dr. Raschke and  
Liberty is just and reasonable in the circumstances. Accordingly, the Board sets the imprudence  
disallowance for the 2006 test year at $15,700,000.  
[96] To avoid any uncertainty going forward, the Board wishes to make it clear that the impact of  
NSPI=s past imprudence for the failings discussed in this decision is now spent and will not extend  
beyond the 2006 test year. This is because, even if NSPI had entered into a multi-year contract in  
2002 and 2003, as the Board considers it should have done, the Board is satisfied that such contract  
would have likely run its course by the end of 2006.  
3.4  
Long-Term Contract  
3.4.1 Submissions - NSPI  
[97] In April of 2005, NSPI entered into a multi-year contract to acquire low sulphur import coal,  
which NSPI states was in accordance with its portfolio strategy. NSPI=s Rebuttal Evidence sets out  
its position with respect to this contract as follows:  
... NSPI solicited the market, evaluated the alternative bids, negotiated with a short list of  
bidders and then selected [the supplier]. According to Liberty, ANSPI properly handled the  
solicitation, including a sufficient number of qualified potential suppliers, conducting bid  
evaluations, and making a decision that appears sound from the information that NSPI  
provided. NSPI procured the least-cost supply offered.@  
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56  
Nevertheless, SEB and Avon=s consultants heavily criticized this transaction. Mr. Marston  
states ANothing in the 2005 Decision justifies NSPI=s decision to enter into a long-term, high  
priced contract near a well-recognized market peak with indifference to market conditions and  
expectations.@(Page 9 Marston evidence) Mr. Gubbins believes the commitment  
[confidential] ran counter to the evidence he had provided the Board. (Page 4 Gubbins  
evidence) Dr. Raschke states that Ahaving adopted an appropriate strategy, NSPI has erred  
in implementing it.@ (Page 48 Raschke evidence)  
This transaction demonstrates very clearly a point NSPI made in its Rebuttal Testimony in the  
2005 Application. Experts disagree. Even reasonable experts disagree. The Board=s  
consultant, Liberty, believed that NSPI should immediately enter into long-term contracts as  
part of a contract portfolio. SEB=s and Avon=s experts believed that NSPI should have a  
contract portfolio but should delay entering into long-term agreements until there was a  
market adjustment. Not surprisingly then, the Liberty consultants applauded NSPI=s contract  
[confidential] SEB=s and Avon=s experts found it imprudent.  
While the Board in its opinion did not contain a specific finding on this matter, it was clear to  
NSPI that the Board believed NSPI should have a contract portfolio and did not disagree with  
its own staff=s consultant, Liberty, that such contracts should be committed to in a timely  
manner.  
NSPI attempted to be responsive to all evidence submitted in the 2005 Application in  
accordance with its own obligations to procure fuel in a responsible manner as follows:  
$
NSPI entered into one multi-year contract at the most competitive price at  
the time the coal was selected with a reputable supplier of high quality coal  
that provided for the maximum volume optionality such that it could reduce  
volumes should the market adjustment occur. Further, NSPI believed that  
this coal provided unique arbitrage opportunities ... The agreement is  
[confidential] not a long-term agreement, which as NSPI=s policies and  
procedures state is desirable for contracts during a high-priced market  
period.  
$
$
NSPI pursued [confidential] contracts with suppliers with indexed pricing  
precisely because of its recognition of the potential market adjustment. The  
pricing in the agreements was not only to be tied to an index but it would  
give NSPI the unilateral right to convert to fixed pricing in the event that (1)  
pricing spiked or (2) pricing fell to very low levels ...  
NSPI expanded its testing program to include tests [confidential] such that  
when the market adjustment occurred it would be prepared to maximize  
competition by having a larger number of sourcing options.  
It is quite telling that the SEB and Avon consultants did not applaud NSPI for its efforts to  
incorporate their world view into the procurement process by minimizing the multi-year  
commitment, seeking contracts with indexed pricing, and conducting multiple tests of  
non-traditional sources.  
(Exhibit N-153, pp. 15-18)  
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[98] In its Closing Argument, NSPI contended that it acted prudently in signing the three-year  
contract and asserted that its decision to do so must be assessed in the context of the following facts:  
$
NSPI had been heavily criticized by consultants and intervenors during the rate  
hearing in November of 2004 for failing to implement a portfolio strategy with  
multi-year contracts in a timely manner;  
$
NSPI had issued a request for proposals for low-sulphur coal in January 2005 and  
concluded that the multi-year offers were not attractive in the context of softening  
world coal prices. Another RFP was issued for April 2005 and the bid prices then  
received were lower than the January 2005 bid prices;  
$
$
Coal prices fallen substantially from their peak in July 2004, but remained volatile;  
Hill & Associates issued its price forecast in March 2005 that predicted continued  
high prices through 2006;  
$
NSPI had advice from its fuel consultant, Emily Medine of EVA, that recommended  
NSPI purchase this coal because it had the lowest evaluated costs of the eight coal  
bids and [confidential] is the premium product in the Atlantic market which may lend  
itself to arbitrage opportunities;  
$
$
$
The [confidential] contract was a medium term contract consistent with NSPI=s  
policies and procedures to use medium term contracts rather than long term  
contracts during higher priced periods;  
The [confidential] contract at minimum contract levels accounted for only about  
10% of NSPI=s solid fuel requirements on a tonnage basis in 2006 and 2007 and  
five percent in 2008;  
The [confidential] contract was only one element of the portfolio being negotiated at  
that time. NSPI also initiated contract negotiations with two other suppliers for  
multi-year agreements based upon index pricing, thereby providing diversification of  
pricing mechanisms for the contract commitments in the portfolio consistent with  
NSPI=s portfolio strategy; and  
$
As a result of the competitive bids for [confidential] at the time, NSPI decided to  
undertake testing programs for these coals to determine if they could be purchased  
in the future (consistent with NSPI=s policy and procedures regarding previously  
untested coals).  
(NSPI, Redacted Closing Argument, pp. 13-15)  
[99] NSPI is of the view that it ought not to be found imprudent as a result of its April 2005  
contract for the purchase of low-sulphur coal. In support of its position, it pointed out that both Dr.  
Raschke and Liberty were of the view that the contract was not imprudent.  
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3.4.2 Submissions - Intervenors and Liberty  
SEB  
[100] SEB, in its Final Confidential Fuel Related Argument, maintained that the overriding  
concern is that NSPI appears to have entered into the April 2005 long-term contract with little, if  
any, consideration of the market.  
[101] SEB expressed the view that, based on Ms. Medine=s evidence, NSPI felt the Aneed@ to  
quickly enter into a multi-year agreement, and that this Aneed@ impacted NSPI=s evaluation of the  
bids received in April 2005:  
The first paragraph under the heading ABid Evaluation@ in Exhibit N-169 is very telling:  
Under normal circumstances a term bid is evaluated both against its  
competition as well as the expectation for market prices. This is not a  
normal circumstances given NSPI=s commitment to develop its portfolio and  
the need to enter into a term agreement at this time. Therefore, a  
Atraditional@ contract evaluation is not performed in which the contract  
alternatives are compared simply against market [Emphasis added in  
original]  
. . .  
Ms. Medine summarized NSPI=s position at Transcript, Page 811 as follows:  
So, it had nothing specifically to do with whether the Company was coming  
back or not [Ait@ being the implementation of a fuel procurement portfolio]  
but there was clearly evidence in the proceeding in the summaries C in the  
submissions that NSPI=s customers C and it was confirmed by the Board in  
its decision in March C wanted more portfolio strategy implemented quickly.  
(SEB, Final Confidential Fuel Related Argument, p. 24)  
[102] SEB referred to a comment by Mr. Gubbins in his Direct Evidence, emphasizing an  
observation made by him in the 2005 rate case:  
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59  
From the standpoint of NSPI=s present highly exposed position, long-term  
contracts should now only be considered after the coal market returns to a  
more balanced level of supply/demand.  
. . .  
Mr. Gubbins= testimony, and SEB=s position on this matter, could not have been made  
clearer during the 2005 proceeding or in SEB=s argument in that case. Their view was that  
from the standpoint of NSPI=s then existing highly exposed position, long term contracts  
should only be considered after the coal market had returned to a more balanced level of  
supply/demand, which was simply not the case in April of 2005. There was no reference  
anywhere in SEB=s argument to NSPI Aimmediately@ or Aquickly@ entering into a portfolio  
(Transcript, page 1706)  
(SEB, Final Confidential Fuel Related Argument, pp. 25-26)  
[103] SEB commented that:  
In this proceeding, Mr. Gubbins specifically noted:  
A. It=s certainly not consistent with the long-term aim of having a  
portfolio strategy, and I think my point I would always make is you  
shouldn=t be where you are now. Therefore the strategy you=ve  
got in place is certainly a long-term strategy, that you=ve got to take  
time to get there, and you=ve got to make sensible purchasing  
decisions in the period to getting there. I mean, you=re in a period  
of very high prices still. In fact, the prices have come off quite  
considerably. This makes it very important that you don=t just rush  
into a strategy that says you have to have long-term contracts  
because somebody, you think, has said you=ve got to have long-  
term contracts. You=ve got to go through something which makes  
sense. You=ve got to have a sensible coal purchasing programme,  
and then you move into the long-term strategy that you=re talking  
about when the market conditions are right and when they=re  
stable, when you can see something - - you can actually see  
what=s happening. I think you=ve pointed out the fact that there=s  
been tremendous uncertainty around the whole time. That is not  
the time to go into long-term contracts. (Transcript, pages 1267-  
1268)  
(SEB, Final Confidential Fuel Related Argument, p. 26)  
[104] The following quote from SEB=s Final Confidential Fuel Related Argument sets out, in  
some detail, its views of the contract entered into by NSPI in April, 2005:  
As the foregoing discussion indicates, the record in this proceeding simply does not justify the  
entering into of the [confidential] contract as a prudent decision by NSPI considering the  
then existing market prices for imported [confidential] coal. SEB respectfully submits that  
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the record in this proceeding has clearly demonstrated significant doubt as to the prudence of  
entering into the [confidential] contract, and as explained earlier the burden has shifted to  
NSPI to demonstrate that this contract was both reasonable and prudent. As described in  
Appendix A the jurisprudence imposes a clear requirement that NSPI produce evidence of  
what its decision was based upon, and not only does it bear the burden of proving that its  
decisions were prudent, but it must also put forward evidence of what activities it undertook to  
underpin those decisions. SEB submits that NSPI has not demonstrated to the Board  
through the Hearing process that Aratepayers money [has been] wisely and frugally spent@  
as the Board required in its October 23, 2002 Decision (see Appendix AA@).  
SEB respectfully submits that NSPI has failed to discharge is [sic] burden of demonstrating  
that its contracting decision was prudent, in that it has not provided a record which  
demonstrates the decision Ato be the result of a logical process, guided by a reasonable set  
of considerations, encompassing relevant information known or which should have been  
known at the time@ (see Appendix A). In fact, the exact opposite is demonstrated by the  
record. NSPI read the Board=s 2005 Decision to mean that it had to move Aquickly@ to  
develop a portfolio of contracts. SEB submits that nothing in the Board=s 2005 Decision  
suggests this is the case. In fact, the issue with respect to timing raised by the Board in the  
2005 Decision was NSPI=s failure to act in a timely fashion in entering into longer term  
contracts in the late 2002/2003 time period which was the basis for the Board=s $18 million  
disallowance discussed above. The Board was concerned that NSPI had not entered into  
longer term arrangements at a time when market prices were low; there is no indication in the  
2005 Decision that it was suggesting that NSPI should subsequently enter into longer term  
arrangements when market prices were high.  
Furthermore, as noted by Mr. Antonuk=s comments earlier in this Submission (Transcript,  
page 2456), the utility and not the Board is charged with the burden of making reasonable  
and prudent management decisions.  
NSPI appears to have fundamentally misunderstood the Board=s findings with respect to the  
2005 imprudence disallowance and furthermore, and more importantly, with respect to the  
[confidential] contract, felt that the 2005 Decision somehow mandated that it develop longer  
term contracts as part of a portfolio strategy notwithstanding market conditions.  
This Aneed@ to act Aquickly@, the lack of an evaluation against market, and little or no  
supporting documentation from NSPI=s management or in-house fuel procurement  
department, does not provide a basis for NSPI to be able to support a finding of prudence  
with respect to the entering into of the [confidential] contract.  
As Mr. Gubbins initially indicated in his Direct Testimony (Ex. N-90) at pages 6 and 7, and in  
the Spreadsheet attached to his response to NSPI IR-3 (Ex. N-137), the appropriate  
disallowance to be made on account of the [confidential] contract was $5.8 million. His  
revised spreadsheet incorporating the [confidential] calorific correction discussed previously  
shows a proposed disallowance of $4.1 million.  
Mr. Gubbins specifically noted at page 6 of his Direct Evidence (Ex. N-90) as follows:  
In April 2005 NSPI entered into a long term contract to purchase  
[confidential] coal ...  
We would question the wisdom of this decision since it goes directly against  
the advice that we gave in the 2004 hearing. The coal market is cyclical,  
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61  
having peaked in July 2004, but still being at very high levels in April 2005.  
Since this date prices have declined further in spite of increasing oil prices  
(see figures 1 and 4), illustrating that coal prices are not entirely linked to  
overall energy prices but determined by their own dynamics in the market  
place. Figures 1, 4 and 5 illustrate the cyclicality of coal prices with cycles  
traditionally 5 to 6 years in duration as we indicated last Fall. Figure 5  
shows that there is a close correlation between changes in demand and  
prices ... The cycles appear to be getting shorter and volatility greater.  
NSPI therefore entered into a long term contract when, although softening,  
prices were still high. In our view the prudent course would have been to  
have waited and continue with a short term purchasing strategy as we  
indicated last Fall.  
The trend line for imported ... coal has continued to be downward since the date of the filing  
of Mr. Gubbins= evidence.  
Interestingly, as noted above, Dr. Raschke although not stating that the contract was  
imprudent per se, pointed out that the costs to other NSPI ratepayers of the decision to enter  
into the [confidential] contract were Aconsiderable@....  
NSPI contends that they find support for their decision in the evidence of the Liberty Group.  
The Board should note however that NSPI finds favour with Liberty=s conclusions when they  
are in accord with NSPI, but yet does not accept any of Liberty=s suggested adjustments  
when they are not in accord with the utility (Transcript, pages 2001-2003). Furthermore,  
Liberty appears to favour a portfolio approach to contracting and therefore felt it was  
appropriate for NSPI to commence the development of that portfolio, but they note the  
fundamental lack of support in the record for NSPI=s decision-making as previously noted. It  
is in fact NSPI=s failure to rationally support its decision to enter into the [confidential]  
contract, together with the contract=s pricing vis a vis market trends for 2006, that support the  
requirement for a disallowance. SEB submits that the cross examination of the NSPI fuel  
panel, subsequent to the filing of Liberty=s evidence and the examination of Dr. Raschke,  
further demonstrated the inadequacy and irrationality of the decision-making which  
surrounded the [confidential] contract.  
(SEB, Final Confidential Fuel Related Argument, pp. 27-30)  
AVON  
[105] Avon, in its Rebuttal Submission observed that NSPI has made advances in developing and  
implementing a portfolio strategy; however, whether or not the strategy is being implemented in an  
appropriate manner is a different consideration than whether a particular coal contract is prudent.  
[106] Avon took issue with NSPI=s assertion that Dr. Raschke had somehow endorsed the April  
2005 contract, or that he was of the opinion that it was reasonable for NSPI to take immediate steps  
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62  
to implement the portfolio strategy. Avon argued that Dr. Raschke had merely pointed out that it  
appeared NSPI concluded it should act quickly to implement the portfolio strategy; however,  
according to Avon, Dr. Raschke never agreed that this was a reasonable thing to do.  
LIBERTY  
[107] In its Direct Evidence, Liberty had this to say about the April 2005 multi-year contract:  
A.  
NSPI=s April 2005 solicitations sought [confidential] tonnes per year of long-term  
low-sulfur coal supply through 2008. NSPI recognized this solicitation as its first  
attempt to add a long-term solid fuel supply contract to its portfolio, in response to  
the Board=s March 2005 decision. NSPI properly handled the solicitation, including a  
sufficient number of qualified potential suppliers, conducting bid evaluations, and  
making a decision that appears sound from the information that NSPI provided. NSPI  
procured the least-cost supply offered. This procurement was the only long-term  
solid-fuel supply agreement entered during the 2004/2005 period, but NSIP [sic] did  
make shorter term purchases.  
(Exhibit N-97, pp. 30-31)  
[108] Liberty stated, during cross-examination, that it believes NSPI acted prudently in entering  
into the April 2005 contract, and it disagreed with those consultants who were of a contrary view:  
Q.  
And are you aware that some of the consultants on behalf of some of the customers  
have suggested that the company acted imprudently in entering that [confidential]  
multi-year deal?  
A.  
(Spangenberg) I=m aware of that.  
Q.  
Would you - - is it true that Liberty does not share that view but instead believes that  
Nova Scotia Power acted prudently in entering the [confidential] multi-year  
agreement?  
A.  
(Spangenberg) Yes.  
(Transcript, November 29, 2005, pp. 2365-2366)  
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3.4.3 Findings  
[109] The Board has carefully considered the matter of the April 2005 contract. The importance of  
having a balanced portfolio strategy for fuel procurement was discussed at length in the last rate  
hearing. In the 2005 rate decision, the Board commented as follows:  
[65]  
Colin V. Gubbins of the McCloskey Group, Richard Marston of Marston & Marston  
Inc. and Sharon Hennings of Brubaker and Associates Inc. all gave evidence on behalf of  
SEB with respect to fuel. Both Mr. Gubbins and Mr. Marston provided their views with  
respect to world coal markets and NSPI=s fuel procurement practices in pre-filed direct  
evidence and in their testimony at the hearing. Both experts take a similar view of NSPI=s  
procurement strategy. They do not believe it is appropriate. In their opinion, NSPI has not,  
since 2002, adequately pursued a balanced portfolio of short, mid-term and long-term coal  
supply contracts and, consequently, customers are not adequately protected against price  
volatility. They were critical of NSPI=s solicitation of the market between 2002 and 2004 for  
long-term contracts. They noted that coal prices had reached low levels in late 2002 and that  
Ms. Medine=s evidence in the 2002 hearing, which indicated that NSPI should pursue a  
balanced portfolio of short, mid and long-term contracts, was correct. In their view, NSPI did  
not act quickly or effectively enough to follow this advice.  
[66]  
Mr. Gubbins and Mr. Marston generally agree that NSPI had a window of opportunity  
in late 2002 and early 2003 to lock in reasonably priced, long-term coal supply contracts.  
They indicated that NSPI overlooked this opportunity and, instead, focused on shorter term  
contracts. As a result, NSPI and its ratepayers are exposed to a sharp increase in coal prices  
and, had NSPI acted prudently, this price increase could have been reduced. Mr. Marston, in  
Exhibit N-71, indicated that NSPI relies primarily on market timing in solid fuel purchases,  
rather than clear guidelines or price objectives. His opinion is that the solid imported fuel  
costs projected by NSPI for 2005 are A... based on an unreasonable and imprudent fuel  
procurement strategy and are unreasonably high because of NSPI=s over-exposure to short-  
term and spot contracts.@ Mr. Gubbins advises that, despite the reference to 24 months as  
the preferred maximum length of fuel supply contracts noted in NSPI=s new manual, long-  
term contracts are generally understood in the industry to be between three and five years in  
length.  
[67]  
Dr. Manfred Raschke, of International Strategic Information Services, gave fuel  
evidence on behalf of Avon. He is also of the view that a balanced portfolio of short, mid-term  
and long-term coal supply contracts is necessary to avoid high risk exposure to coal price  
volatility and is essential for a prudent fuel procurement strategy. He indicated that, in his  
opinion, NSPI does not have a balanced portfolio for coal supply and, as a result, NSPI and  
its customers are vulnerable to spot markets and price volatility. Dr. Raschke also pointed  
out that had NSPI moved quickly to adopt a balanced portfolio in late 2002 and early 2003  
(which was Ms. Medine=s advice during the 2002 rate case) it could have reduced the impact  
of the high 2005 coal costs it now faces.  
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[68]  
Liberty expert witnesses were John Antonuk, Donald T. Spangenberg, Jr., Dennis  
Kalbarczyk and John B. Adger, Jr. They took a similar view with respect to NSPI=s fuel  
procurement strategy. Mr. Spangenberg indicated that his review of NSPI centred on fuel  
management, particularly coal. He testified that, in his opinion, NSPI did not use a balanced  
portfolio approach to secure coal supplies and that NSPI=s fuel procurement procedures, as  
well as the structure of its organization and internal expertise relating to this issue, are  
inadequate.  
(Board Decision, March 31, 2005, pp. 32-34)  
[110] In its 2005 rate decision, the Board set out Liberty=s recommendations concerning the fuel  
portfolio strategy:  
Mr. Spangenberg=s recommendations are:  
1.  
NSPI should immediately conduct an overall re-evaluation of its  
generating system to determine the optimum way of meeting new  
requirements for control of SO2 emissions, as well as emissions of  
other pollutants of concern, from its generating plants. Such re-  
evaluation should incorporate a long-term view, not just the next  
several years. The recommended study should consider not only  
all fuel supply options, but also integration of fuel supply options  
with capital expenditures for alteration, modification or expansion of  
its generating units in order to achieve the lowest possible costs for  
generation of power, consistent with other issues of reliability,  
environmental concerns and legal issues.  
2.  
3.  
Consistent with item #1 above, NSPI should immediately revise its  
fuel portfolio strategy to incorporate a balance of both short-term (or  
spot) and long-term fuel contracts with terms ranging from one up to  
seven years, with expiration dates not all occurring at the same  
time.  
NSPI should adopt a consistent policy of annual solicitations for  
long-term coal supply that are accompanied by production quality  
model runs for at least seven years into the future in order to  
determine actual fuel requirements. Such model runs should also  
provide the base for evaluation of proposals received from coal  
suppliers in order to conduct analysis of variances, such as fuel  
switching costs to comply with the lower SO2 emission  
requirements.  
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65  
4.  
NSPI should revise its coal solicitation process to make it an  
aggressive one that conveys the image of a utility operating from a  
position of professionalism and strength. RFP language must be  
clear and correct, and RFP=s must be very clear about the specific  
fuel supply needs of the future, in terms of tonnes of coal required  
for each year in the future up to a maximum of seven years. Do not  
leave tonnages and years of supply at the discretion of fuel  
suppliers. NSPI must demonstrate it is a professional and serious  
fuel buyer that knows what it wants, and when it wants it.  
(Board Decision, March 31, 2005, p. 36)  
[111] The Board concluded that A... The prudency and effectiveness of a balanced portfolio of  
short, mid-term and long-term coal contracts was unquestionable....@28  
[112] The Board also stated:  
The issue, in the Board=s opinion, is not NSPI=s stated intention to improve its  
practices but the timeliness and effectiveness with which actual implementation of the new  
approach was achieved. NSPI, in the Board=s view, failed to address its imported coal  
procurement problems quickly or efficiently enough to adequately protect itself or its  
ratepayers. Had it done so expeditiously following the 2002 rate hearing, the Board is  
satisfied that, based on the evidence at this hearing, it was possible for NSPI to create a  
balanced portfolio of short, mid-term and long-term imported coal at reasonable prices.  
Instead, NSPI appears to have slowly implemented the necessary changes to its  
procurement practices. It remains unclear to the Board whether the corporate philosophy  
actually changed, and whether the procedures and practices recommended by Ms. Medine  
are yet fully implemented, particularly with respect to the need for long-term coal supply  
contracts which exceed terms of twenty-four months.  
(Board Decision, March 31, 2005, pp. 47-48)  
[113] There is no question that the message to NSPI from the Board=s 2005 rate decision was that  
a balanced fuel portfolio had to be implemented as soon as possible. The Board stated that the issue  
was not NSPI=s intention to improve its practices, but its timeliness and effectiveness in achieving  
28Board Decision, March 31, 2005, para. 80  
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the new approach. Liberty had specifically stated that NSPI should A... immediately revise its fuel  
portfolio strategy to incorporate a balance of both short-term and long-term contracts ...@  
[114] The Board=s decision was issued on March 31, 2005, and NSPI entered into its first multi-  
year contract in April of 2005. Coal prices had fallen somewhat at the time, and although they were  
still fairly high, there was no assurance that NSPI could achieve more favourable prices by waiting  
out the market. Certainly, the forecasts of various experts were no guarantee which way coal prices  
would trend. The absence of a balanced portfolio left NSPI in a particularly vulnerable position.  
NSPI acted with dispatch in entering into the contract. One of the advantages of a portfolio  
approach to coal purchases is that it balances high costs with low costs and does not rely on  
outguessing the market. The adoption of a balanced portfolio approach will, by its very nature,  
result in some contracts being entered into during periods of relatively high prices. It would be  
dangerous, in the Board=s view, to undermine a balanced portfolio strategy by insisting that all  
multi-year coal contracts be entered into only during periods of relatively low prices. The reality is  
that no one knows, except with the benefit of hindsight, whether prices are going to go up or down at  
any particular point in time. Otherwise, there would be no need to have a balanced portfolio strategy  
in the first place.  
[115] Accordingly, the Board finds that the April 2005 contract was not an imprudent transaction.  
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3.5  
Affiliate Activity  
3.5.1 Submissions - NSPI  
[116] In its Rebuttal Evidence, NSPI outlined the nature of the relationship between NSPI and  
Emera Energy Services (EES), an affiliated company to which NSPI sells its natural gas:  
As in the last rate application Board staff consultants have commented on the contract with  
Emera Energy Services (EES) for resale of natural gas contracted to NSPI.  
This contract has built-in transparency and has been a significant benefit to NSPI customers.  
NSPI previously advised the Board that the contract term was being extended so as to not  
prejudice the gas supply contract arbitration. NSPI has also informed the Board that a  
reputable third-party will supervise a new solicitation, and participate in the evaluation of bids  
that come forward during this solicitation.  
NSPI disagrees with the characterization that it does not treat gas resales as a core utility  
function. In competitively identifying a third party to buy and resell its natural gas NSPI  
structured the arrangement so that it maintained control over the following:  
!
!
!
!
The amount of gas sold or burned;  
The amount of gas sold monthly or. [sic] Daily;  
Management of the gas cuts from NSPI=s supplier;  
The ability to hedge the volume and price of gas.  
The contract provides a premium value over the gas market price- -an advantage to NSPI=s  
customers. The contract does not take away from the underlying market value. NSPI has  
the mechanisms to participate in the value the gas market can provide.  
None of the above stated functions is controlled by the affiliate. NSPI, through daily and  
monthly instructions, directs EES. EES, as bound by the contract, pays NSPI pursuant to the  
agreed pricing structure which is fully transparent. NSPI still maintains full responsibility for  
the sale of its natural gas. The contract does not take away NSPI=s ability to manage supply  
cuts, generation requirements, monthly versus daily pricing and with financial hedging.  
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NSPI decided to enter a term arrangement to sell its natural gas, for exactly the reasons  
Liberty stated were not considered. As referenced in documentation provided in the last rate  
application outlining the evaluation of the bids for the resale of natural gas, NSPI was  
concerned that sophisticated buyers were taking advantage of the fact that NSPI must either  
sell its gas or burn it. To protect value for customers NSPI needed an arrangement that  
locked in the value of the market. The RFP and resulting contract did that, securing a  
premium to an M3 published index in the winter months and no less than market driving other  
months. In comparison bids from other counterparties offered less value. Given  
uncertainties with supply and demand the EES contract offered the best price and flexibility.  
(Exhibit N-153, pp. 48-49)  
[117] NSPI, in its Closing Argument, reiterated that the resale of natural gas has been a  
significant benefit to NSPI=s customers, and that NSPI intends to continue to dispose of its  
excess natural gas in this manner. It stated that ANow that the arbitration process is  
complete, NSPI is arranging for a reputable third-party to supervise a new solicitation, and  
participate in the evaluation of bids that come forward during this solicitation.@29  
29NSPI, Redacted Closing Argument, p. 93  
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[118] At the hearing, Counsel for NSPI clarified its intent to select a reputable third-party to  
supervise the new solicitation. James L. Connors, Q.C., Counsel for NSPI, stated that "...The  
correspondence which has gone to the Board which refers to a third party is a proposal, and the  
company is now actively pursuing this, to select an independent third party who would administer  
the RFP process for gas sales next year. So, in other words, what's under way is the picking of an  
expert independent company who will then be the ones who run the RFP..."30  
[119] During cross-examination of the NSPI Fuel Panel by David MacDougall, Counsel for SEB,  
Ralph Tedesco, NSPI=s Chief Operating Officer, outlined the process underway for the selection of  
the independent third party, and he stated that the Company had, after identifying somewhere  
between 12 and 16 third parties, narrowed the field to two who would be offered the opportunity to  
administer the solicitation process. Mr. Tedesco also confirmed that EES was not one of the two  
finalists with respect to the solicitation contract.31  
[120] In its Closing Argument, NSPI discussed the transparency of the sale of its natural  
gas, and quoted the evidence of Chris Huskilson, President and Chief Executive Officer of  
NSPI, as follows:  
30Transcript, November 29, 2005, p. 2423  
31Transcript, November 25, 2005, pp. 1993-1994  
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Mr. Chair, just for clarification, I would like just a couple of clarifying points on this if you don=t  
mind. First of all, I think it should be clear to the Board that all these transactions are being  
done at market transparent pricing, so it - - again, that=s a very recognizable and transparent  
way to do business, for sure. The second thing is that any transaction that=s done in this  
light is done such that things like the credit exposure is being transferred between the  
company, Nova Scotia Power, and the affiliate. So there=s a significant credit exposure that  
Nova Scotia Power doesn=t have to bear. And ultimately, that B you know, that is part of B  
one of the reasons why Nova Scotia Power would want to do this. And just the last point is  
that when you look at these transactions, they don=t actually bear on setting the forward price  
of electricity or the future test year because all of those things are done based on the way  
that we look at market forward prices and so on, and any of these transactions only happen  
after the price of electricity is set.  
(NSPI, Redacted Closing Argument, p. 93)  
[121] NSPI stated that Liberty has put forth no evidence to show that NSPI=s customers  
experienced any loss of benefit or harm as a result of NSPI=s dealings with EES.  
If there were any doubt about the clear benefits that are provided to customers by this  
particular contract with an NSPI affiliate, Liberty would certainly be presenting a  
recommendation to reduce the test year revenue requirement accordingly. No such  
recommendation has been made ... NSPI submits that the contract with its affiliate, EES, is in  
the best interests of customers.  
(NSPI, Redacted Closing Argument, p. 95)  
[122] NSPI referred to Undertaking U-84 which provided a summary of the net income  
accruing to EES as a result of selling the gas which it purchased from NSPI. NSPI pointed  
out that the summary indicates that the net income arising from such sales is a very small  
percentage of EES=s overall business.32  
32NSPI, Redacted Closing Argument, p. 94  
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3.5.2 Submissions - Liberty  
[123] In its Direct Evidence, Liberty discussed affiliate transactions relating to heavy fuel oil  
(HFO) and natural gas.  
[124] With respect to the acquisition of HFO, Liberty indicated that it found the same type of  
problems which existed in the solicitation process for coal and petcoke. It stated that:  
... We reviewed the solicitation that the Company conducted for its 2005 requirements for  
HFO. We found documentation problems similar to those for coal and petcoke procurement.  
All eight firms on the original bidders list for the solicitation received the RFP. However, the  
documentation does not provide any analysis of bids; it contained only a purchase order  
approval signed by NSPI management. The documentation does not discuss why the award  
to [confidential] constituted the best supply option for NSPI, and there is no management  
approval documentation providing authority to proceed with the award of business to this  
supplier.  
(Exhibit N-97, pp. 62-63)  
[125] Liberty reviewed the HFO transactions between NSPI and Emera Fuels, an affiliated  
company. It concluded that there were purchases in significant amounts by NSPI from Emera Fuels  
in both 2004 and early 2005. Liberty also concluded that NSPI sold HFO to Emera Fuels. Liberty  
stated that:  
The response to Liberty IR-20 gives reason to suspect that these procurements do not follow  
normal processes with respect to competitive purchases and management approvals. There  
is, moreover, the question of whether they otherwise took place at arm=s-length, considering  
that they involved an affiliate.  
(Exhibit N-97, pp. 64-65)  
[126] Liberty expressed concern over these transactions, and suggested that the misgivings which it  
expressed in the last rate case about affiliate transactions have been substantiated and broadened as a  
result of its findings in the present case. Liberty concluded that:  
... a utility should not buy or sell what it otherwise would not, just because an affiliate happens  
to have or need the commodity in question...  
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We can think of no practical way to measure what, if any, affect [sic] affiliate transactions of  
this type will have on expenses in a future year. We can, however, state that they have the  
potential, based on what we have observed at other enterprises that permit purchase and  
sale transactions between utility and non-utility affiliates, to have a significant impact on utility  
costs.  
It is for these reasons that we recommended before and continue to recommend an audit of  
affiliate transactions and relationships within Emera, as they affect NSPI costs and  
operations.  
(Exhibit N-97, pp. 65-66)  
[127] Liberty noted that Emera had recently sold Emera Fuels. Thus, Emera Fuels is no longer  
directly affiliated with NSPI, and it may be that all transactions between NSPI and Emera Fuels will  
cease before the commencement of 2006. However, Liberty pointed out that sometimes there are  
transitional provisions which provide for a continuation of existing relationships, and it  
recommended that this matter should be reviewed in the next year to determine if there are any  
effects on NSPI operations from any ongoing transactions with the new owners of Emera Fuels.33  
[128] Liberty also discussed the arrangement whereby NSPI sells to EES the natural gas that NSPI  
has available under contract, but which it does not use for generating electricity.  
[129] Liberty stated in its Direct Evidence:  
Q.  
WHAT IS YOUR OPINION OF THESE ARRANGEMENTS?  
A.  
The descriptions of the competition process and the resulting arrangements in the  
response to Liberty IR-99 were neither clear nor accurate (although NSPI corrected  
the inaccurate information in responses available on October 3, 2005). Our  
examination indicates that NSPI did not conduct a sufficiently competitive process in  
making its decision. This process and the arrangements that resulted from it were  
not consistent with good utility practice or evidently compliant with the Company=s  
obligations under the Final Code of Conduct, Paragraph 6.1 of which provides that  
33Exhibit N-97, pp. 67-68  
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the Company will A... not ... offer any preference or favoured treatment to NSPI=s  
affiliates ...@.  
Q.  
CAN YOU DESCRIBE HOW MARGINS AVAILABLE TO NSPI CHANGED  
BEFORE AND AFTER ENTERING THE ONE-YEAR AGREEMENT WITH EES?  
A.  
Exhibit LCG-9 attached to this evidence presents information extracted from the  
parent company=s Annual Report for 2004. The table shows that NSPI substitution  
of HFO for natural gas in fueling its power generation allowed the sale of gas for  
more than it cost, thereby producing a net negative gas cost. After EES became the  
exclusive purchaser of NSPI=s gas, however, the benefit of such gas sales fell by  
half. At the same time, EES=s margins were doubling.  
. . .  
Q.  
WHAT DO YOU MAKE OF THE FACT THAT THE ARRANGEMENT WITH EES  
AVOIDS THE NEED FOR NSPI TO SELL THE GAS IN THE U.S. MARKET?  
A.  
The utility could and should sell its own gas, crediting all of the realized margins to its  
fuel-cost accounts, absent clear evidence that the intervention of a marketer like EES  
adds value in excess of the costs or lost margins that also come with the use of that  
marketer. The sales at issue here are reasonably typical off-system sales, which are  
routinely conducted by many utility companies in the U.S. Moreover, one should  
question whether the U.S. location of gas sales is the full reason behind the use of a  
marketer, given that EES appears to be using some of the gas purchased from NSPI  
to make sales within Canada.  
. . .  
Q.  
WOULD IT BE REASONABLE FOR NSPI TO SELL ITS GAS DIRECTLY TO  
PARTIES SUCH AS THOSE WITH WHOM EES EVENTUALLY TRANSACTS?  
A.  
Yes. EES has a track record in the business, but it is a short one. It also has a staff,  
but duplicating its size and level of experience would not be that hard for NSPI. We  
have examined natural gas distribution utilities that make comparable off-system  
sales with very small staffs. Typical is a company we recently examined; it uses a  
staff of five people to conduct all of that company=s gas-supply planning and  
capacity and commodity contracting. Those same five people also conduct a  
secondary-market program (off-system sales and capacity-release transactions) that  
involves about three times the volume that EES sells for NSPI. Our brief review of  
EES staffing confirms that they use a similarly small staff. Liberty has performed  
similar reviews at a number of other utilities, all of whom have secondary-market  
programs, with comparable findings. Making off-system sales is just not that hard.  
. . .  
Q.  
ASSUMING FOR THE MOMENT THAT NSPI SHOULD NOT SELL THE GAS  
ITSELF, WHAT SHOULD IT DO IN SELECTING ANOTHER PARTY TO CARRY  
OUT THAT FUNCTION FOR IT?  
A.  
Q.  
It should secure an arrangement through arm=s-length bidding.  
WHAT DID YOU LEARN ABOUT WHETHER NSPI CONDUCTED SUCH A  
PROCESS?  
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74  
A.  
We examined the documentation that NSPI provided about its solicitation process.  
That documentation exhibited a number of anomalies.  
. . .  
Q.  
WHAT DID YOU CONCLUDE ABOUT WHETHER THE DEALINGS WITH EES  
TOOK PLACE AT ARM=S LENGTH?  
A.  
We concluded that the available information gave substantial reason to conclude that  
NSPI did not make an even-handed effort to give all the potential buyers an  
opportunity to compete on a comparable basis. Rather, the appearance from the  
documentation was that NSPI first took from three third parties their opening or  
Asticker price@ positions, and only then asked its affiliate to stake out a position.  
Then, it took that position, which did not offer clearly superior terms and conditions,  
as a basis for deciding to negotiate with its affiliate to the exclusion of the others. In  
other words, EES appears from the documentation to have gotten an opportunity to  
make a refined offer that NSPI compared against the opening or first positions of the  
competitors.  
(Exhibit N-97, pp. 69-78)  
[130] Liberty also expressed the view that the arrangement between NSPI and EES did not accord  
with the Board=s findings in the 2002 rate case. It stated that:  
We believe that the agreement with EES raises problems under the 2002 order in the  
following respects:  
!
!
!
!
It treated gas sales as not representing a core utility function  
It transfers a major portion of that function to an affiliate  
It took away a key part of NSPI responsibility for gas sales  
It did so without substantial information addressing EES capabilities relative  
to other providers  
!
!
!
It did so without a full consideration of customer risk, conflict, and harm  
It reduced income available to NSPI  
The agreement with EES did not result from bidding or from what may be  
described as real competition  
!
It did so without prior Board approval.  
We believe that the agreement fails to comport with good utility practice in the following  
respects:  
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!
There was no apparent structured process for determining NSPI=s  
capabilities to generate substantial margins through internal conduct of the  
function or any estimation of the difference in net benefits to be produced by  
such internal conduct  
!
!
There was not a sufficiently competitive process for awarding the business,  
assuming that it should have been conducted outside NSPI  
The affiliate received substantial advantages in what was not an arm=s-  
length selection process.  
(Exhibit N-97, pp. 83-84)  
[131] With respect to Liberty=s recommendation that there should be an audit of affiliate  
transactions as they impact NSPI costs and operations, Liberty explained this further in response to  
questions from the Board:  
Q.  
A.  
Q.  
Just on that point, I believe one of your recommendations is that there be an annual  
audit of affiliate transactions.  
(Antonuk) Not necessarily annual, but periodic.  
What sort of -- when you talk about an audit of affiliate transactions, you have  
comments in here concerning affiliate transactions. In your view, how would an audit  
of affiliate transactions differ from, in essence, what you have done in order to be  
able to make your comments that you made in here about the affiliate transactions,  
how would that differ?  
A.  
(Antonuk) Well, the first thing it would do is typically it would proceed over the course  
of probably more like a 5 to 6 month period, so that there could be a more, from an  
audit perspective, orderly and careful flow of information than is ever going to be  
possible in a rate case with the deadlines that, from an affiliate's audit perspective,  
frankly just don't work. You know, if you've got only so much time to ask a DR and  
you can't follow it up and you can't go back and sit down with management and say  
"What about this? Here's my concern about that", you can't have -- you just can't get  
to the bottom of these issues realistically in a rate case construct primarily because  
it's a -- forgive me for saying this, it's kind of a legal-driven process rather than a  
business and management-driven process. And also because a rate case, for good  
reasons, has to operate on deadlines. The other thing it would do is it would not limit  
you to looking at things that do or don't have a direct impact in a test year but still  
may be influencing over the long term utility costs in a very significant way, you  
know, cost allocations, for example. You know, whether common organization  
structures exist to serve utility/non-utility affiliates and whether, in fact, the company's  
allocating cost properly. When they're dealing with third parties, you get the code of  
conduct issues, and an affiliate's audit usually also goes into those and validates that  
the company's not only meeting the express limits of the code of conduct but it's also  
doing what it needs to do to encourage third parties to believe that there is true  
competition. So it's those kinds of issues. Those audits often end up coming back  
and having relevance in a rate case if you find something wrong and there happens  
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to be a rate case, you know, that shortly proceeds [sic] it. But the real benefit of  
them, I think, is it gives a Commission or, in your case, a Board, confidence over the  
long run that the utility is being run as a utility and not as an entity that exists to  
provide profit opportunities for affiliates.  
. . .  
Q.  
A.  
Excuse me, your recommendation doesn't just -- is not just confined to energy  
affiliates, is it?  
(Antonuk) No, I don't think it should be. No, it should not be. It should address them  
all, although when you're doing a work plan for an affiliate's audit, if the non-energy  
stuff is minor in terms of potential consequence, you would -- obviously your work  
plan would call for very little time on that. And, like I said, we have not gone through  
that process of sort of saying where are all the risks. I think we do have a pretty good  
handle on where the energy risks are, and a lot of them are addressed in the report.  
The other thing an affiliate audit does, which I think is something that's very hard for  
a lot of people to see, is this. When you have affiliates who are dealing with a third  
party community like energy buyers and sellers, and a utility that's dealing with them,  
you may not see any transactions between the utility and the affiliate, but what we  
have found in the past sometimes is what you do see is there's a third party out  
there, maybe a big supplier, who's given the affiliate a good deal and is charging the  
utility more. Now, I'm not saying that's common, you know, most people don't do that,  
but we have discovered that. But that's something where you would have to look  
even where there aren't direct transactions between a utility and a non-utility affiliate  
and say is there some common third party out there that's providing a vehicle for  
distribution of costs or revenues in a way that's inappropriate. And I'm not suggesting  
there's -- you know, that we have reason to think that there's any of that kind of  
conduct going on here, but it is one of the things that as a matter of due diligence we  
believe needs to be checked periodically.  
Q.  
A.  
Given your time frame, 5 to 6 months, it likely wouldn't be practical to do this on a  
yearly basis.  
(Antonuk) No, and we don't think they're necessary on a yearly basis. You know, I  
guess it's in my interest to say frequently, but, you know, if they're on -- using people  
who come in and do a good look every three or as long as five years is fine provided  
whoever's doing that is leaving the staff with kind of, you know, a checklist to use in  
between to let the staff see if any of the base lines of performance or transactions  
are changing in the interim. So you could go with maybe a five-year cycle and then  
have the staff just run through the diagnostic checklist with the company every  
maybe 18 months or even 2 years.  
Q.  
A.  
In your view, is this a significant recommendation? I mean, is this something you feel  
strongly about that should be done?  
(Antonuk) Yes. And that's based both on our general belief in the importance of  
them, and also in the specific things we've seen here, even more so the latter in this  
case is the specifics we've seen.  
(Transcript, November 29, 2005, pp. 2433-2438)  
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[132] During Mr. Connors= cross-examination of Liberty, he asked about any proposed  
adjustments to the revenue requirement as a result of affiliate transactions:  
Q.  
Thank you. Now, Mr. Adger, you've made some comments with regard to affiliate  
transactions and some questions about certain aspects of the historical relationships.  
Would you agree that your company has not proposed any adjustment to the test  
year revenue requirement with regard to those matters?  
A.  
(Adger) That's correct.  
Q.  
And would you also agree with me that relations between Nova Scotia Power and  
any affiliates within 2005 you're not suggesting that that affected in any way  
customer rates in 2005?  
A.  
(Adger) I think I have to qualify a response to that, because we remain concerned  
that the structure for the sale of Nova Scotia Power's gas that it receives from  
[confidential] is -- does not maximize the value of those gas sales. However, the  
rates were set based on some estimate of it, so that lack of value maximization  
affects Nova Scotia Power but not the customers in 2005.  
(Transcript, November 29, 2005, pp. 2467-2468)  
[133] Mr. Connors also asked Liberty about its recommendations that there be periodic audits of  
affiliate transactions:  
Q.  
A.  
Q.  
And are you aware that a chartered accountant firm independent of the company  
already conducts an annual audit of compliance with the code of conduct?  
(Adger) I was not specifically aware of that but ---  
No. And are you aware -- so I take it then you would not be specifically aware that  
that company has provided reports for the past year and before that we've had  
several annual reports filed with the Board in that regard by that accounting firm?  
(Adger) I would expect that to be the case. I would say, though, that it has been our  
experience that accounting firms sometimes don't find things that people with more  
expertise in those kinds of transactions found.  
A.  
Q.  
A.  
Would the SEC have more expertise in the area of affiliate transactions?  
(Antonuk) No.  
Q.  
A.  
Not at all?  
(Antonuk) No. Well, I can't comment on their expertise. Their level of scrutiny, I think,  
is pretty weak, though, over affiliate transactions.  
Q.  
I see. So, if I suggested to you that the company underwent a regular audit of affiliate  
transactions in the past year by the SEC, an audit that took place over a number of  
months, you're going to say that the outcome of that is something the Board  
shouldn't pay attention to?  
A.  
(Antonuk) No, let's get on the straight -- on the same question. I thought you meant  
the United States Securities and Exchange Commission.  
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78  
Q.  
A.  
That's exactly who I'm talking about.  
(Antonuk) Yeah. I don't think their audits of affiliate transactions are particularly  
effective at finding the kind of things we're talking about.  
Q.  
A.  
I see.  
(Antonuk) We've looked at many of them.  
Q.  
A.  
You understand, but were you aware of the fact that there has been an affiliate  
audit?  
(Antonuk) I would not expect there not to be, I'm just saying that I don't see how it  
bears on what we were talking about.  
Q.  
A.  
I see.  
(Antonuk) We know that's the case with the utilities we've examined, and if you look  
at our reports there are a lot of things we find that they don't -- never even choose to  
look at.  
Q.  
A.  
If I suggest to you the affiliate audit conducted by the SEC raised none of these  
issues ---  
(Antonuk) I'd say that's pretty typical of every -- virtually every Liberty report you see  
where we find material problems. That's why I said I don't think the SEC is very deep  
or effective at looking at these issues. Their concern isn't utility customers.  
(Transcript, November 29, 2005, pp. 2468-2470)  
[134] Liberty expressed concerns that the arrangement between NSPI and EES was not entered into  
on an Aarm=s-length basis@:  
... the available information gave substantial reason to conclude that NSPI did not make an  
even-handed effort to give all the potential buyers an opportunity to compete on a  
comparable basis .... In other words, EES appears from the documentation to have gotten an  
opportunity to make a refined offer that NSPI compared against the opening or first positions  
of the competitors.  
(Exhibit N-97, pp. 77-78)  
[135] Liberty stated that the process and arrangements with EES were not consistent with good  
utility practices and, further, were not in compliance with the Company=s Code Of Conduct.34  
34Exhibit N-97, p. 69  
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[136] Liberty suggested that NSPI should be selling its own gas, and A... crediting all of the  
realized margins to its fuel-cost accounts, absent clear evidence that the intervention of a marketer  
like EES adds value in excess of the costs or lost margins that also come with the use of that  
marketer.@35 Alternatively, Liberty expressed the view that, if NSPI does not sell its own gas, but  
selects another party to do it, then NSPI should do so through an arm=s-length bidding process.36  
3.5.3 Findings  
35Exhibit N-97, pp. 70-71  
36Exhibit N-97, p. 73  
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[137] The Board has considered whether or not it should direct NSPI to re-assume the selling  
function for its natural gas not utilized in the generation of electricity. NSPI has stated in its Rebuttal  
Evidence of November 7, 2005, that it needs A... an arrangement that locked in the value of the  
market. The RFP and resulting contract did that, securing a premium to an M3 published index in  
the winter months and no less than market driving [sic] other months...@37 NSPI argues that EES  
offered greater value than others did, and given the uncertainties with supply and demand, the best  
price and flexibility was obtained with the EES contract.  
[138] The Board notes that Undertaking U-84, which sets out the details of the margins earned by  
EES on its sales of natural gas and power, indicates that the income arising from the gas EES has  
purchased from NSPI is a very small percentage of EES=s total business. It is clear to the Board,  
based on Undertaking U-84 and other evidence filed during the hearing, that the resale of NSPI=s  
gas constitutes a very small component of EES=s operations, and that in order for NSPI to assume  
the task of selling its own natural gas, it would be obligated to establish the necessary internal  
infrastructure, including employing the necessary number of employees possessing the skills to deal  
effectively in the natural gas markets.  
[139] NSPI has committed to engaging in an RFP process to select a new party to handle its natural  
gas, and that the selection of the new party will be based on an objective assessment of the RFP  
responses by an independent third party. It is possible that EES, or another affiliate of NSPI, could  
be chosen to handle the NSPI natural gas contract; however, the choice will be made on an arm=s-  
length basis by an independent third party.  
37Exhibit N-153, p. 49  
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[140] Given these circumstances, the Board is not prepared at this time to require NSPI to assume  
direct responsibility for selling its surplus natural gas. However, the Board will monitor the  
transactions and the relationship between NSPI and the company selected to handle NSPI=s natural  
gas, particularly if the arrangement should be with an affiliated company.  
[141] Liberty has recommended that NSPI conduct a study to determine the feasibility of  
establishing an in-house capability to sell its own gas.  
[142] The Board agrees with this recommendation and directs that NSPI carry out such a study and  
to file it with the Board by August 31, 2006.  
[143] Liberty also recommended that periodic audits be carried out on affiliate transactions and  
NSPI=s relationships with Emera and Emera subsidiaries.  
[144] In its 2005 rate decision, the Board stated:  
The Board also notes the concerns expressed with respect to other affiliate transactions  
involving energy and fuel. It is evident from the issues raised that reviewing NSPI=s annual  
filing on affiliate transactions solely by an accounting firm, however well qualified, is likely  
insufficient. Accordingly, in addition to the form of review on this information performed in the  
past, the Board, in future, will also retain fuel audit experts to examine and express their  
opinions on these types of affiliate transactions, including export sales and natural gas sales.  
(Board Decision, March 31, 2005, pp. 63-64)  
[145] Liberty outlined, in oral evidence, how the audit of affiliate transactions and relationships  
should be conducted. Primarily, it envisages an audit carried out every three to five years which  
would take a few months to complete. This would allow the audit to proceed in an orderly and  
thorough manner, which would not be possible if it were being conducted as part of a rate case. The  
audit, which would review significant transactions with all affiliates, would be designed to review  
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items which may not directly impact test year figures, but which may have significant long term cost  
implications for NSPI.  
[146] In Liberty=s opinion, the real advantage of these periodic audits is that they will provide the  
Board with meaningful assurances that NSPI is being run properly as a utility, and not as a vehicle  
A... that exists to provide profit opportunities for affiliates.@38  
[147] The Board accepts the recommendation of Liberty to implement a process of detailed,  
periodic audits of affiliate transactions. Due to Liberty=s extensive knowledge of NSPI, gained as a  
result of its work during the last two years, the Board will retain Liberty to carry out the first audit.  
During 2006, the Board will request Liberty to prepare a detailed work plan for the first audit,  
including the estimated time and budget, as well as an appropriate commencement date. The Board  
directs that the work plan be filed with the Board by June 30, 2006 for Board approval. The Board  
intends this audit to be carried out on a professional basis by experienced experts in utility matters,  
including the energy and fuel functions, as well as affiliate transactions. NSPI will be consulted  
during this process and its opinions solicited. The Board, in planning the commencement date for  
the first audit, will give consideration to other time commitments which may be facing NSPI.  
[148] The reason the Board considers this audit to be an important step is because NSPI=s parent,  
Emera, has become a large multi-faceted organization, with many affiliates, and NSPI engages in  
numerous transactions with some of these affiliates. In order to properly carry out its mandate  
pursuant to the Public Utilities Act, the Board must be able to satisfy itself that these inter-affiliate  
38Transcript, November 29, 2005, p. 2435  
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transactions are being conducted in accordance with the Code of Conduct and that they are also  
properly accounted for in the records of NSPI, thereby ensuring that NSPI is receiving all profits to  
which it is justly entitled.  
[149] The detailed audit of affiliate transactions is not meant to replace the annual reporting  
required under the Code of Conduct. Rather, these annual filings will be extremely useful in the  
design of the work plan for the audit of affiliate transactions, and the Board will ensure that there is  
no duplication of effort between PWC and Liberty, with respect to the periodic audit of affiliate  
transactions.  
3.6  
Point Tupper Marine Terminal  
3.6.1 Submissions - NSPI  
[150] In its Direct Evidence, NSPI provided a brief outline of the Point Tupper Marine Terminal  
(APTMT@):  
The Point Tupper Marine Terminal (PTMT) is a bulk unloading facility located adjacent to the  
Point Tupper generating station. PTMT can accommodate gearless vessels, or bulkers, which  
were previously not an option for NSPI. This option increases competition among coal  
suppliers and provides access to lower cost supplies of coal, and can result in suppliers  
revising bids to compete with alternative supply basins. The location and design  
of the terminal were chosen to:  
$
$
Substantially reduce demurrage charges through faster unloading capability;  
Eliminate rail transportation costs from the port to the Point Tupper plant;  
and  
$
Allow for bulkers which usually have lower transportation costs and allow  
shipments from more distant ports.  
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The PTMT began commercial operation early in 2005, receiving the first vessel as part of the  
commissioning process in January, ahead of schedule. Following competitive bids, NSPI  
chose Savage CANAC Corporation, the Canadian affiliate of a leading US service provider in  
the bulk material handling industry, to manage the operation of the marine terminal. The  
parties entered a 10-year contract starting April 1st, 2005....  
(Exhibit N-1, pp. 58-59)  
[151] In its Rebuttal Evidence, NSPI furnished additional information about the PTMT, including  
why it was built:  
When NSPI began to import coal in 2001, there were no coal import facilities in the Strait of  
Canso to support delivery to the Trenton and Port Tupper generating stations. NSPI was able  
to negotiate an agreement with Martin Marietta to unload coal at its aggregate operation in  
Aulds Cove. The Martin Marietta facility was relatively small and not equipped to handle large  
vessels. Only self-unloading vessels could be unloaded at the Martin Marietta facility and  
demurrage was always due as the vessels could not be unloaded at the standard contract  
rate of 2,500 tonnes per hour. Coal from the Martin Marietta facility had to be railed or trucked  
to Point Tupper and Trenton. Further, there was very limited storage at the Martin Marietta  
facility.  
As noted in EVA=s review of NSPI operations, NSPI negotiated a 30-month agreement with  
Martin Marietta that started in October 2002. The agreement provided Asufficient time for  
NSPI to determine its best long-term for supplying Trenton and Point Tupper.@ EVA noted  
A(t)he Martin Marietta facility as configured provides a good stop-gap alternative for NSPI but  
may not make sense long-term because of the inherent inefficiencies in how the vessels are  
unloaded and its limited storage capacity.@ In order to increase storage at the Martin Marietta  
facility, a second pad was added on an area away from the port and rail link but was not  
desirable as NSPI incurred an extra cost every time it was used.  
NSPI conducted a systematic process for identifying alternatives to the Martin Marietta  
facility. NSPI advertised for parties interested in providing terminal services and/or bidding to  
develop a terminal at Point Tupper. NSPI determined the least cost strategy to be a terminal  
at Point Tupper, and selected a third party to own and operate it.  
As the Board is aware, NSPI=s plan for the terminal faced certain challenges when it was not  
able to consummate an agreement with the selected third party. NSPI, following discussions  
with the Board, decided to go forward with the terminal outside of the traditional capital  
approval process in order for the terminal to be completed in a timely manner. NSPI  
estimated that it would incur $3 to $4 million in additional costs in 2005 if it delayed  
development of the facility. At the time, NSPI committed to attempt to divest the terminal once  
it was operational or return to the Board to ask that the cost of the facility be put into rate  
base.  
The Board, in a letter dated January 22, 2004 noted that Athe Board has no objection to NSPI  
constructing the terminal outside rate base. At such time as NSPI applies to the Board to  
have the terminal included as part of rate base, or applies to the Board to have the terminal  
sold and leased back to NSPI the Board will determine whether or not the proposed  
transaction, and its related costs, is appropriate after performing its normal review  
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procedures.@ NSPI proceeded with the terminal and completed construction in a timely  
manner such that the unloading of vessels destined for Trenton and Point Tupper was  
accommodated by PTMT upon the expiration of the Martin Marietta agreement.  
While NSPI has not abandoned its efforts to sell the terminal, it has entered into a 10-year  
operating agreement with Savage for its operations. The Savage contract was produced for  
review as part of this proceeding.  
. . .  
NSPI is still marketing PTMT and hopes to sell it to a third party. Absent that, NSPI will ask  
the Board to put the capital into rate base. In the interim, capital recovery on PTMT is  
appropriate given the undisputed value it has provided NSPI with respect to both direct  
saving, which NSPI estimates to be [confidential] in 2006 alone when NSPI is purchasing  
relatively little of its fuel requirements from non-traditional sources, and indirect costs related  
to the increased competition in coal supply.  
(Exhibit N-153, pp. 43-47)  
[152] In its rate application, NSPI has included in the fuel expense an amount of $2.3 million,  
which represents the equivalent to a capital charge recovery on the terminal. These funds are not  
being paid to Savage, but represent a capital recovery charge on the terminal. In essence, the charge  
represents a recovery to NSPI for its capital related expenses in carrying the facility. The facility has  
not been approved for addition to rate base, as set out above.  
[153] NSPI, in its Closing Argument, stated that "... NSPI is seeking to recover in its fuel expense a  
$2.3 million proxy fee for capital recovery while NSPI uses the full capacity of the PTMT for the  
benefit of customers."39  
39NSPI, Redacted Closing Argument, p. 41  
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[154] NSPI took issue with both Dr. Raschke and Sharon Hennings, of Brubaker and Associates  
Inc., with respect to their proposed disallowances relating to the PTMT and, in particular, "...  
relating to the inclusion of a proxy for capital cost in the fuel expense calculation. Neither  
consultant has expertise in marine terminal design, capacity, and operation, and both appear to  
understand the significant benefits to NSPI and its customers that PTMT delivers."40  
[155] In UARB IR-61, NSPI set out the breakdown of the $2.3 million capital recovery charge. It  
includes an estimate for depreciation, interest expense on the short-term debt to finance the PTMT, a  
rate of return on the equity component invested in the terminal, and the related income tax effects.  
[156] With respect to the claim by Ms. Hennings that NSPI does not utilize 100% of the capacity  
and thus should not be able to recover the total amount of the capital expense, NSPI, in its Closing  
Argument, quoted from its response to SEB IR-197:  
40NSPI, Redacted Closing Argument, p. 41  
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In order to minimize demurrage, PTMT was designed such that belted self-unloading  
Panamax vessels could off load at a rate of 3,000 tonnes per hour. The unloading capacity of  
the crane used for bulker-type vessels was designed for approximately 800 tonnes per hour,  
which balances terminal capital costs and demurrage charges for this type of vessel. PTMT  
must agree to allow delivery of nominated ships within a period the length of which is  
negotiated between the parties. The more distant the source, the longer the period must be.  
For example, a 20-day window is not uncommon for deliveries from Indonesia. In order to  
avoid demurrage, NSPI minimizes the overlapping of delivery windows, which limits the  
number of ships that can be accommodated. The PTMT maximum design capacity for  
storing solid fuel is 164,000 tonnes. This capacity is just sufficient to unload vessels  
and maintain the flow of solid fuel to the plants. The inventory storage and daily feed  
storage areas for the Point Tupper station is 44,000 tonnes. The Point Tupper unloading  
area under the unloading trestle is 50,000 tonnes. The Trenton unloading storage area under  
the trestle holds 70,000 tonnes, which allows for a full bulker Panamax vessel to be unloaded  
when the area is empty. The Trenton storage volume is transferred via a rail shunt to the  
Trenton generating station five days per week. The terminal is not designed to handle  
commodities other than solid fuels. [Emphasis added in original]  
(NSPI, Redacted Closing Argument, p. 44)  
[157] NSPI stated that the above information makes it clear that Ms. Hennings= views concerning  
the capacity of PTMT are incorrect.41  
3.6.2 Submissions - Intervenors and Liberty  
SEB  
[158] Ms. Hennings, an expert witness appearing on behalf of SEB, discussed the PTMT in her  
Direct Evidence:  
Q.  
A.  
Please provide background information about NSPI=s Point Tupper Marine Terminal.  
Point Tupper Martine Terminal (PTMT) was completed in early 2005, at a total cost  
of $34.6 million, (Avon IR-56). NSPI is the current owner of PTMT, (NSDOE IR-64).  
NSPI is currently trying to sell PTMT, and it has not been its intention to own the  
terminal. NSPI claims that the costs included in the 2006 forecast for PTMT are  
justified by savings on its Point Tupper and Trenton coal receipts, as compared with  
its coal receipts using the dock at Auld=s Cove.  
41NSPI, Redacted Closing Argument, p. 44  
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Q.  
A.  
Could the PTMT handle more than the current requirements of Point Tupper and  
Trenton?  
Yes, the PTMT could handle several times the current requirements of these  
generating plants...  
Q.  
A.  
What ratemaking treatment is available for the capital costs of the PTMT?  
For an asset included in the utility=s assets, regulatory bodies sometimes eliminate  
part of the investment costs from rate base if the utility has built excess capacity that  
is not both used and useful. The used and useful criteria could be applied to the  
PTMT annual cost of capital of $2.30 million per year.  
NSPI has constructed an asset that it has proposed to charge as though it is part of  
rate base. It has calculated both depreciation and rate of return in developing a cost  
of $2.3 million to pass to ratepayers. From the bid information in the request for  
proposals when NSPI attempted to sell this asset, it has at least 50% more capacity  
than will be used during 2006 for utility purposes. Based on the delivery capability of  
this asset, it is capable of several times more delivery capacity than necessary for  
utility operations. The entire PTMT facility may only have NSPI as its sole customer  
during the year, so PTMT will likely qualify as being used by NSPI. However, only  
part of the shipping capacity is useful to NSPI. Thus, PTMT has excess capacity for  
utility purposes. The cost of this excess capacity should not be passed through to  
ratepayers in 2006.  
Q.  
A.  
What level of elimination of capital costs are you advocating?  
NSPI=s $2.3 million proxy for the cost of capital should be reduced by at least one  
third ... Based on the delivery capability of the asset the Board may wish to consider  
an even greater reduction.  
(Exhibit N-91, pp. 2-5)  
[159] SEB, in its Final Confidential Fuel Related Argument, stated that NSPI is seeking to recover  
not only the operating costs which it pays to Savage, but also the $2.3 million related to the capital  
costs of the PTMT. SEB believes that the Board should adopt the recommendation of Dr. Raschke  
that no capital recovery be allowed to NSPI in the 2006 test year because none of the PTMT's capital  
costs have been included in rate base. SEB also indicated that, although Ms. Hennings had  
recommended only a partial disallowance, she could also support Dr. Raschke's recommendation.  
[160] SEB explained these points as follows:  
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NSPI has indicated that it has not abandoned its efforts to sell the terminal, and it has  
not yet applied to the Board as contemplated in the Board=s letter of January 22, 2004.  
Accordingly, NSPI=s inclusion of $2.3 million on account of capital for the PTMT in fuel costs  
is merely a back door route to recovery of its capital where the Board has not yet conducted a  
review of the capital expenditures for PTMT and has not included it in rate base. In these  
circumstances, SEB submits it is highly inappropriate to allow for this capital cost recovery as  
a part of fuel expense.  
Depending on whatever arrangements NSPI may ultimately enter into by way of sale  
and leaseback, NSPI could easily end up over-recovering its costs from ratepayers. The  
Board is simply not in a current position to allow for this recovery, as it specifically stated in its  
January 22, 2004 letter. Section 35 and subsection 35A(1) of the Act require NSPI to obtain  
Board approval for any new construction, improvements or betterments in or extensions or  
additions to its property used or useful in furnishing, rendering or supplying any service which  
requires the expenditure of more than $25,000, or approval of an annual capital expenditure  
program.  
Subsection 42(1) of the Act provides that the Board shall fix and determine the  
appropriate rate base for NSPI, and subsection 42(2) indicates that in establishing a rate  
base the Board shall determine the value of the physical assets of the public utility in  
accordance with the provisions of the Act, and sets out various factors that the Board should  
consider.  
To date the Board has not determined Awhether or not the proposed transaction, and  
its related costs, is appropriate@, nor has it conducted its normal review in this regard. In  
these circumstances NSPI=s claim for capital cost recovery is not supportable, and indeed  
likely not permissible.  
However, if the Board is somehow of the view that it is appropriate and permissible  
for NSPI to recover a portion of its capital through its fuel costs, SEB submits for the reasons  
specified in Ms. Hennings= Direct Evidence, pages 2 through 5 (Ex. N-90), that the $2.3  
million be reduced by one-third, i.e. $767,000. It appears that PTMT will certainly not be fully  
utilized, and various bidders who responded to NSPI=s RFP to own and/or operate PTMT  
appear to be of the view that the facility could accommodate up to [confidential] million  
tonnes of coal and also possibly be utilized as a trans-shipping or off-loading base for other  
customers (see Ex. N-205). In essence, as described above under the description of the  
Aused and useful@ test, PTMT is not fully Aused and useful@ for NSPI=s regulatory purposes,  
and NSPI should not be entitled to a return on its fully booked cost in 2006.  
(SEB, Final Confidential Fuel Related Argument, pp. 54-55)  
[161] SEB submitted that it would be completely inappropriate to allow a utility to recover the  
costs of an asset not in rate base:  
With respect to the argument that PTMT has not been approved for recovery in rate  
base, NSPI states at page 45 that:  
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It is appropriate from a regulatory rate making perspective to include  
recovery of the operating component as well as a proxy for the capital  
component of the investment within the context of the fuel expense.  
NSPI provides no citation to support this bold assertion, and no evidence of where such  
treatment has been allowed. SEB respectfully submits that this would in fact be completely  
inappropriate from a regulatory rate-making perspective.  
(SEB, Final Confidential Fuel Related Rebuttal Argument, pp. 16-17)  
Avon  
[162] Avon, in its Closing Submission, had the following to say with respect to the PTMT:  
NSPI has constructed the Point Tupper Marine Terminal (PTMT) for the stated  
purpose of accommodating larger vessels and expanding the range of supply sources for  
import coal. At the present time, NSPI has been trying to sell the PTMT and it has not  
applied to the Board to have the terminal included as part of the rate base. NSPI has entered  
into a ten year operating agreement with Savage Canac for operation of the PTMT.  
NSPI has accounted for the payments to Savage Canac valued at [confidential] for  
PTMT and [confidential] for Trenton in its fuel costs and in addition, it is seeking to recover  
$2.3 million as equivalent to a capital cost. It is this latter amount which we dispute.  
. . .  
Dr. Raschke has submitted that NSPI should not be permitted to include in its fuel  
costs any of this $2.3 million capital recovery for PTMT. While NSPI=s rebuttal evidence  
suggests that Dr. Raschke has not offered evidence with respect to the actual capital costs  
and NSPI=s prudence or imprudence in building the facility, the fact of the matter is, this is  
not the forum to do so. If and when NSPI applies to have the PTMT brought into rate base, it  
is at that time that Dr. Raschke may have something further to say.  
. . .  
Sharon Hennings offered an alternative recommendation with respect to the PTMT  
suggesting that the Aused and useful@ criteria could be applied to disallow at least 1/3 of the  
claimed cost on the basis that PTMT has excess capacity for utility purposes.  
Ms. Hennings also confirmed in her testimony that she supported the  
recommendations of Dr. Raschke that capital recovery be disallowed for the PTMT in 2006  
because the capital costs have not been included in the rate base, indicating that his  
recommendation is supported by the letter of January 22, 2004, from the Board. This letter  
was referred to by NSPI in its rebuttal evidence and filed subsequent to Ms. Hennings=  
evidence.  
It is telling that the PTMT amortization costs, Aequivalent to capital costs@ were  
included in forecast 2005 results even though NSPI did not apply for these costs to be  
included in rates and the Board made no direction in this regard.  
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There is no regulatory precedent for including the PTMT amortization costs as an  
equivalent to capital in the fuel budget. We respectfully submit these ought to be disallowed  
in their entirety.  
(Avon, Redacted Closing Submission, pp. 19-21)  
Province  
[163] In its Closing Submission, the Province expressed significant reservations concerning NSPI's  
claim for a $2.3 million capital recovery:  
NSPI is seeking $2.3 million for what it characterizes as a fuel expense which is the  
equivalent to capital recovery on the Point Tupper Marine Terminal. NSPI=s position is that if  
the Point Tupper Marine Terminal were owned by a third party, capital recovery would be  
included in lease payments, and thus form an operating expense that would flow into its fuel  
costs. It argues that since the Point Tupper Marine Terminal is generating transportation  
related savings in excess of the $2.3 million claimed, its capital related recovery is justified. It  
is troublesome that NSPI is seeking capital recovery on an unapproved capital asset, and that  
the amount that it seeks to recover in 2006 along is well in excess of the $1 million threshold  
for identifying capital projects that require separate review and approval.  
Expected savings generated by a capital asset might provide justification for the  
approval and construction of the asset, but they should not be used as a justification for  
capital recovery without approval. While NSPI=s position might very well turn out to be  
correct, that a cost benefit analysis would support this capital asset, the Province does not  
believe that the Board has been provided with a cost benefit analysis of the same quality as  
would be expected to support an application for a capital project. The Province is also not  
certain that all of the potential costs associated with the facility have been thoroughly  
presented. For example, the facility supports the Trenton generating station and there may  
very well be additional costs incurred given that the Point Tupper facility is further away from  
Trenton than the Martin Marietta facility at Auld=s Cove.  
The argument that capital costs would be imposed on NSPI if the facility was owned  
by a third party is also not satisfactory. If that third party was Emera or another NSPI affiliate,  
surely such an arrangement would warrant close regulatory scrutiny. It should not be any  
different when the asset is owned by NSPI=s unregulated split personality.  
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The $2.3 million claimed by NSPI is derived from the asset value and a depreciation  
rate that has not been approved by the Board and that could be varied by the Board, if and  
when NSPI ever does see fit to move forward with a proper regulatory review of this asset.  
Without a proper regulatory review one cannot be certain that the claimed $2.3 million is not  
an over recovery, regardless of the level of operational savings that the asset purportedly  
generates. The Province submits that NSPI=s capital recovery relating to the Point Tupper  
Marine Terminal should be tied to a directive that it proceed to apply to the Board for approval  
to include the asset in its rate base. Furthermore, the Board should provide that any capital  
gain, should the facility be sold in the interim, be credited to NSPI=s regulated personality.  
(Province, Redacted Closing Submission, pp. 22-23)  
Liberty  
[164] Liberty, in its Direct Evidence, reviewed the solicitation and evaluations in connection with  
the appointment of Savage to operate the PTMT:  
Q.  
APART FROM THE LONG-TERM COAL CONTRACT SOLICITATIONS THAT  
YOU HAVE JUST BEEN DESCRIBING, PLEASE LIST ANY OTHERS THAT YOU  
EXAMINED.  
A.  
We reviewed the solicitation and evaluations associated with the selection of Savage  
to own and operate the new Point Tupper Marine Terminal. While the solicitation  
was on the basis of selecting a new owner for the terminal, NSPI currently still owns  
the terminal.  
Q.  
WHAT DID YOUR REVIEW SHOW WITH RESPECT TO SUFFICIENCY OF THE  
SOLICITATION PROCESS?  
A.  
Liberty found the solicitation process associated with the Savage agreement to be  
appropriate. The substantive documentation that NSPI provided showed the  
solicitation and the response from bidders to be comprehensive and thorough.  
Liberty did observe, however, that the documentation associated with the Savage  
solicitation and award process contained the same administrative deficiencies as  
described above related to coal and petcoke procurement.  
The original bidders list contained 19 firms, four of which responded. The Savage  
proposal was clearly the most comprehensive, and offered the lowest operating  
costs. Liberty found a clear summary of the issues related to each of the bids from  
all suppliers. NSPI did express some reservations about the Savage bid. At this  
point in the documentation, the information became sketchy. It was not possible to  
determine how or whether NSPI resolved its concerns with Savage. The only point  
that was clear was that the competition narrowed to two providers, but no basis for  
this was provided. The crucial point is that the documentation provided contains no  
analysis indicating why the business was ultimately awarded to Savage. In addition,  
as with the majority of coal and petcoke procurements, there is no management  
approval documentation supporting the award to Savage.  
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(Exhibit N-83(a), pp. 48-49)  
[165] In cross-examination by Mr. Connors, Liberty confirmed that it was not recommending a  
disallowance of any of the PTMT charges.  
3.6.3 Findings  
[166] The Board has considered the evidence surrounding the PTMT. The main concern is related  
to the capital recovery charge of $2.3 million which NSPI wishes to recover as part of its fuel costs  
for the 2006 test year.  
[167] Dr. Raschke was of the view that NSPI should not be permitted to include any of the $2.3  
million in its fuel costs because the PTMT is not in rate base. Ms. Hennings, on the other hand, was  
of the opinion that the PTMT has excess capacity, and that there should be a disallowance of a  
portion of the $2.3 million cost associated with the facility, based on the "used and useful concept".  
She stated that  
... regulatory bodies sometimes eliminate part of the investment costs from rate base if the  
utility has built excess capacity that is not both used and useful. The used and useful criteria  
could be applied to the PTMT annual cost of capital of $2.30 million per year.  
(SEB, Exhibit N-90, Evidence of Sharon K. Hennings, p. 4)  
[168] The Province expressed reservations about allowing a recovery concerning an asset which  
has not been approved for inclusion in rate base.  
[169] Liberty did not recommend any disallowance with respect to the $2.3 million capital  
recovery. However, the Board notes that Liberty criticized the documentation associated with the  
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solicitation and award process, finding that it contained the same type of administrative deficiencies  
as observed in the coal and petcoke procurement process.  
[170] To the Board=s knowledge, NSPI=s request for a capital recovery charge in relation to a  
non-rate base asset is extremely unusual and perhaps unprecedented. The Public Utilities Act  
clearly contemplates that all assets of a utility which are used and useful in supplying a regulated  
service shall be included in the rate base fixed by the Board with respect to that particular service.  
Furthermore, s. 45 of the Act provides that a public utility is entitled to earn a just and  
reasonable return on the rate base fixed by the Board, and to recover reasonable and  
prudent operating expenses. There is nothing in s. 45 or elsewhere in the Act which  
entitles a public utility to recover capital-related charges in relation to assets which it owns  
outside of its approved rate base. Accordingly, in the Board=s view, it would be improper to  
allow the recovery of the $2.3 million in fuel expense. Otherwise, a utility could hold assets  
outside its rate base even though those assets were being used to provide a regulated  
service. It could recover the capital-related charges through rates even though the Board  
had never approved the value of the asset for inclusion in rate base, or for depreciation  
purposes. Having proceeded in this fashion, the utility could then sell the asset without  
having to allocate to its customers any of the profits realized on the sale. This would be an  
intolerable situation which, in the Board=s view, is simply not compatible with the intent or  
express provisions of the Act.  
[171] The Board hastens to add that it is not suggesting any improper motive on the part of NSPI.  
The evidence clearly indicates that NSPI built the PTMT with the intention of selling it. In the  
meantime, it has entered into a contract with a third party to operate the terminal and the Board is  
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satisfied that NSPI=s customers are benefitting from the arrangement. Moreover, despite the  
evidence of Ms. Hennings, the Board is not persuaded that the terminal was designed to have excess  
capacity, although this question need not be definitively addressed unless and until NSPI applies to  
have the PTMT included in rate base. Should NSPI make such an application, the Board is prepared  
to consider at that time whether, in determining the amount to be included in rate base, an allowance  
should be made for deferred capital charges having regard to the fact that the terminal has, since the  
commencement of its operation, been devoted exclusively to the receiving and unloading of coal for  
NSPI=s Trenton and Point Tupper generating plants.  
3.7  
Natural Gas Resale Benefit  
3.7.1 Submissions - NSPI  
[172] NSPI has a long-term contract with a supplier for the purchase of natural gas. When the cost  
of natural gas exceeds the cost of other fuel types burned by NSPI in its generation facilities, the  
Company resells the natural gas and applies the proceeds to reduce its overall fuel costs.  
[173] During the hearing, as previously indicated, NSPI announced it had reached a settlement with  
its supplier on the pricing and supply arrangements of natural gas, as well as other issues under the  
long-term contract. The settlement avoided the risk to both parties of an arbitrated resolution. While  
the details of the settlement are of an extremely confidential nature (and were treated as such during  
the confidential sessions of the hearing), the Company did issue the following public news release to  
the media, investors and financial institutions:  
New Gas Pricing Agreement Reached by Nova Scotia Power  
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Halifax, NS, November 21, 2005 - Nova Scotia Power Inc. (NSPI) announced today that it  
has reached an agreement with its supplier on pricing for natural gas under an existing  
long-term natural gas purchase agreement.  
As a result of the agreement, NSPI will lower its 2006 fuel forecast by $22 million. This will  
reduce the Company's 2006 rate application from an average increase of approximately 15  
per cent to approximately 13 per cent. NSPI has filed supplementary evidence with its  
regulator, the Nova Scotia Utility and Review Board (UARB).  
"This agreement is good news for Nova Scotia Power customers," said Chris Huskilson,  
President and Chief Executive Officer of Nova Scotia Power. "Given market conditions similar  
to today, the customer benefits from this agreement will continue for several years."  
The financial benefits of the agreement will vary based on world energy prices. Nova Scotia  
Power will propose to the UARB that should its 2006 fuel costs be lower (as a result of this  
agreement) than the amount the regulator ultimately provides for in the rate decision, the  
difference will be refunded or credited to customers.  
The agreement provides NSPI with natural gas at a discount to current world market prices.  
By having the option to resell the gas, NSPI and its customers can gain financial benefit.  
The contract - which began in 2000 and runs until 2010 - calls for up to approximately 61,600  
MMBtus of natural gas per day to be supplied to Nova Scotia Power. The contract was  
subject to a price re-determination on November 1, 2004. With both Nova Scotia Power and  
its supplier unable to come to terms last year, the matter was referred to binding arbitration.  
The two companies reached agreement in advance of any arbitration decision. The UARB  
has been provided with details of the agreement which is confidential for competitive reasons.  
"This agreement is more than a year in the making," added Mr. Huskilson. "Customers are  
being asked to cover skyrocketing fuel costs - it's only fair they receive the benefit of this fuel  
contract gain by Nova Scotia Power."  
This agreement also results in a favourable adjustment to NSPI's fuel expense for 2005.  
Consequently, as a result of this agreement and other factors, including warmer weather in  
the fourth quarter, NSPI has revised its financial forecast earnings for 2005 and now expects  
earnings to be approximately $15-20 million lower compared to 2004.  
(UndertakingU-43)  
[174] On a confidential basis, NSPI filed with the Board, and with intervenors who signed  
confidentiality agreements, Supplementary Evidence setting out the terms of the settlement and its  
estimated impact upon the 2006 test year fuel forecast.42 While NSPI stated that the settlement will  
not eliminate all uncertainty respecting the Company's future gas supply costs, or the expected  
42Exhibit N-187  
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margin that can be obtained on the resale of any gas not consumed by the Company, it recognized  
that stakeholders would like some assurances that if results turn out better than originally forecast,  
the benefits would accrue to NSPI's customers. After NSPI provided its estimate of the natural gas  
resale benefit that it expected would be applied against its 2006 fuel budget, it proposed:  
For every dollar that NSPI=s resale gas margin reduces NSPI=s 2006 actual fuel expense  
below the allowed fuel expense in the approved rates pursuant to the filing before the Board,  
NSPI will, at the direction of the UARB, either refund such amounts to its customers or  
reduce future revenue requirements.  
(Exhibit N-187, p. 5)  
[175] NSPI=s Fuel Panel resumed its testimony after the natural gas settlement was filed with the  
Board. In a Supplementary Opening Statement, Mark Sidebottom, NSPI=s Director of Fuels,  
Energy and Risk Management, reported:  
The agreement covers the full term of the contract. It will give NSPI and its customers greater  
certainty in future years. As a result of the favourable negotiating outcome, we have reduced  
our fuel expense for 2006 by $22 million. This works out on average to an approximate two  
percentage point reduction in our rate request, from an average of 15 percent to 13 percent  
overall. That said, the precise value of the contract still depends on natural gas prices, and  
gas production levels.  
The negotiations surrounding the natural gas contract involved a substantial amount of effort  
using both internal and external resources. This result is good for our customers.  
...  
With respect to the natural gas agreement, NSPI recognizes the possibility this contract may  
result in a greater value than $22 million improvement in fuel expense.  
The company proposes that any additional savings from this contract above and beyond the  
fuel budget ultimately set in rates, should be provided to customers as a refund or a credit.  
This is consistent with our position that our intention is to recover our actual fuel expense, no  
more and no less.  
(Exhibit N-188)  
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[176] In cross-examination by John P. Merrick, Q.C., the Consumer Advocate, NSPI=s Policy  
Panel elaborated upon the mechanism NSPI suggests be adopted to account for any additional  
benefits achieved under the new contract (i.e., over the level of the $22 million improvement to the  
original fuel costs estimated by NSPI), and how it would be applied if there was a finding of  
imprudence by the Board:  
Q.  
(Merrick) Is it the position of the company that if there is any surplus revenue from  
gas sales over and above the [confidential forecast margin] that was identified in  
the supplemental hearing then it will not be used to offset or reimburse the company  
for any deduction that might be made for imprudence?  
A.  
(Huskilson) I think I can state the proposal that the company has made, and I think  
that is consistent with the proposal. And that is that we have said that gas revenues  
margin are to be set at the additional 22 million dollars ($22,000,000) which I think is  
[confidential forecast margin], I believe, million dollars now, and that any value  
that we received over and above that number would be deducted from the approved  
amount for fuel expense that was approved by this Board and as long as we had  
costs below that. That's what we proposed, and that's what we continue to propose.  
Q.  
A.  
And would that include costs that you might incur but not be allowed to recover in  
rates because of an imprudence deduction?  
(Tedesco) If the fuel expense, just to pick some numbers, were set out, say, 500  
million dollars ($500,000,000) and there was, for the sake of discussion, a ten million  
dollar ($10,000,000) disallowance, then the fuel budget would be set at four hundred  
and ninety million dollars ($490,000,000). The gas, again, sake of discussion, say  
added twenty million dollars ($20,000,000) of value to customers, so that would then  
lower the fuel budget then would be set at four hundred and seventy million dollars  
($470,000,000). To the extent we came in below 470 million dollars ($470,000,000),  
then yes, the benefit of the gas contract would accrue to customers. To the extent we  
came in above 470 million dollars ($470,000,000), then no, it would not.  
Q.  
A.  
Q.  
A.  
Q.  
When you say "we came in," it would be your total expenses coming in below that  
number.  
(Tedesco) That's correct.  
Including expenses that, for rate setting purposes, might have been deducted for  
imprudence -- a penalty for imprudence.  
(Tedesco) Correct.  
So that the short answer to my question is that if there were deduction for  
imprudence, the company would still look to apply gas revenue against that before it  
would turn anything back in.  
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A.  
(Tedesco) Yes, if we came in below. And I think the idea here would be there are  
bad things, there are good things. We think the gas contract is a good thing. It is not  
unreasonable that one, under those circumstances, should offset the other.  
Otherwise, we're simply playing a one-sided game.  
(Transcript, December 1, 2005, pp. 3202-3204)  
[177] The Policy Panel provided further insight on this issue in response to questions from Board  
Counsel:  
Q.  
A.  
Q.  
And you then had a discussion with Mr. Merrick about the company's proposal for  
dealing with the gas resale benefits in excess of [confidential forecast margin]?  
(Huskilson) Yes, sir, we did.  
You recall that. And to be certain that I understand the answers you gave to Mr.  
Merrick on that question, I want to put a simple hypothetical to you. And I emphasize  
that it's a hypothetical. Assume for the sake of argument only that the Board were to  
make an imprudence disallowance of ten million dollars ($10,000,000) on fuel in this  
proceeding. Now assume also that your fuel cost projections for 2006, except for the  
gas resale benefit, prove to be spot on. In other words, all your other fuel  
assumptions are correct. Thirdly, assume that the gas resale benefit in 2006 actually  
turns out to be [confidential forecast margin plus $10 million], which is precisely  
ten million higher than the base estimate of [confidential forecast margin], which  
you've asked to be built into the fuel budget. Now, in those circumstances, under the  
company's proposal, would any of the ten million dollars ($10,000,000) in extra gas  
resale benefits flow to customers or would it all go to the company?  
A.  
(Tedesco) In the hypothetical that you've described, the way that ten million dollars  
($10,000,000) would flow would be to pay the company's fuel costs, and that would  
be no different than our fuel budget today. So for instance, as already exists in our  
budget, as we've demonstrated in an earlier undertaking, coal is slightly below  
forecast, HFO is slightly above forecast. There is no argument that the cost of HFO B  
I haven't heard anyone say, "Well we should adjust the company's fuel budget  
upward nine or ten million dollars because of the cost of HFO." What we are saying  
is that the proposal that we've put forward is precisely consistent with how the Board  
has set rates in the past. The strip that we have used for gas is our assumption that  
was the gas price assumption presented in our filing. Based on that filing, we have  
estimated benefit of the gas contract of [an additional] twenty-two million dollars  
($22,000,000). If it turns out it's less, that's at the company's risk. If it turns out it's  
more, that's at the company's benefit. In either case, the customer is not harmed  
once the fuel budget is set.  
Q.  
Mr. Tedesco, I understood all of those parts. I just wanted to be sure, under the  
company's proposal, what happened to that ten million dollars ($10,000,000).  
(Tedesco) You've characterized it correctly.  
A.  
...  
Q.  
In other words, the upshot is -- and I realize that it can be characterized a number of  
ways, and I'm not disagreeing with what Mr. Tedesco has said -- but the effect of it  
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is, in this hypothetical which I posed, the company would recover its full fuel budget  
including the ten million dollars ($10,000,000) that was found to be imprudent prior to  
any gas resale benefits flowing to customers. That's the bottom line.  
(Tedesco) Well, it's -- I wouldn't characterize it that way.  
A.  
Q.  
A.  
I realize you wouldn't ---  
(Tedesco) It's really ---  
Q.  
A.  
--- but that's what would happen. Nothing would go to customers until the amount --  
the excess exceeded ten million.  
(Tedesco) That's right. But it would be no different than the risk that we take on  
today. There is nothing to say that fuel -- that gas prices will change in such a way  
that we may end up under-recovering. There is nothing to say that the gas deliveries  
-- as I said earlier, we believe we have a very aggressive assumption on gas  
deliveries. There is nothing to say that those deliveries will not show up. These are  
risks that the company takes on, and as I said last night, what we're -- really all we're  
asking for is we'll take the good with the bad. We don't want to be punished for doing  
something good.  
(Transcript, December 2, 2005, pp. 3282-3286)  
[178] In its application filed July 5, 2005, NSPI=s projection for the gas resale margin was based  
on the May 2005 forward price strip for natural gas. Following the announcement of its settlement,  
NSPI updated its estimate of the anticipated resale margin that may be achieved under the  
settlement. At the request of Board Counsel, NSPI provided an update using the May 2005 forward  
price strip (increasing the benefit by $22.6 million) and using the November 2005 forward price strip  
(increasing the benefit by $64.1 million).43  
[179] In the testimony of Dr. Stutz, discussed in greater detail below, he proposed setting up a  
reserve fund, equal to any excess of the actual gas resale margins for 2006 (above the amount  
43Supplemental Stutz IR-8 (updated November 25, 2005) and Undertaking U-58 (filed December  
6, 2005)  
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included in rates), to be distributed to the benefit of the Company and its customers following  
consideration, in a future rate hearing, of results achieved during the 2006 test year.  
[180] NSPI submits that Dr. Stutz's proposal imposes all the risk of future natural gas price  
fluctuations upon the Company. In cross-examination, the Policy Panel expressed the following  
concerns about his proposed reserve fund, and its future distribution:  
A.  
(Tedesco) Dr. Stutz's proposal is different from ours.  
Q.  
A.  
(Merrick)Would you have any objection to Dr. Stutz's proposal?  
(Tedesco) Yes, I would.  
Q.  
A.  
And what would be the basis of your objection?  
(Tedesco) Again, the company is simply looking to recover its fuel costs, both good  
and bad, and whatever they may be and wherever they may be set, to the extent we  
beat that target, then we would agree those costs should accrue to customers. It's  
not fundamentally different, in my mind, than some of the proposals that have been  
put forth during the hearing by some to say, well, we should reduce the fuel budget,  
certain [coal] contracts are below forecast, while ignoring that certain other oil  
contracts are above forecast.  
A.  
A.  
(Huskilson) And I think, Mr. Merrick, I think it would be important to say that the  
proposal that the company has made is very similar to the circumstance that it finds  
itself in today or has found itself in the past. And so we would see that that proposal  
is not changing the circumstance the company has always had, whereas the  
proposal -- this proposal looks like it does change those circumstances. And so that's  
why we would take issue with it.  
(Tedesco) I think we need to be very conscious of we're in an environment with  
volatile fuel costs. We find ourselves today in a circumstance in part because of  
imprudence, in part because of dramatically higher fuel costs where we have,  
indeed, a bow wave. To continue to scoop or seek to scoop only the good and ignore  
the bad I think only builds that bow wave for future years.  
(Transcript, December 1, 2005, pp. 3206-3207)  
[181] The Policy Panel reiterated these concerns in cross-examination by Board counsel:  
Q.  
(Outhouse) ...You have said, as I understood Mr. Huskilson to say yesterday to the  
Board, be very careful how you price that gas under the contract because if ... you  
set that margin too high, then it could come back to haunt us if we don't realize that  
margin, and the company could be seriously harmed, as I understood you, Mr.  
Huskilson.  
A.  
(Huskilson) That's exactly right. And so the proposal that we have made allows the  
company to have some protection around that issue, but also allows some  
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opportunity for customers to see the benefit of that. And so we thought that that was  
balanced. If the proposal that Dr. Stutz was making was a two-sided proposal, one  
that would say, "We're going to set up an account for the gas contract" and pluses or  
minuses would be flowed through, that would be a different kind of arrangement  
which would be more aligned to the kind of suggestion the company has made. And  
that would be a different arrangement that might make more sense.  
...  
Q.  
A.  
Dr. Stutz's proposal does not create any down-side risk on the gas contract for the  
company.  
(Huskilson) Yes, it does.  
Q.  
A.  
How?  
(Huskilson) Because the [confidential forecast margin] is not assured.  
Q.  
A.  
No. But that's the company's proposal too.  
(Huskilson) I understand.  
Q.  
A.  
So his proposal doesn't add to that risk.  
(Huskilson) No, it doesn't add to that risk, but it takes another risk component -- or  
adds another risk component to the company, which is the overall fuel situation. And  
that increases the risk. So the company was willing to take the risk that the  
[confidential forecast margin] was a good number based on the fact that there was  
a balance on the other side.  
Q.  
A.  
Mr. Tedesco?  
(Tedesco) It would certainly be our hope and position that this issue be moot. And I  
say that from the perspective of we do not believe there has been imprudence. If  
indeed there is no imprudence, there is no issue with the company's proposal, and  
any benefits will accrue 100 percent to customers.  
(Transcript, December 2, 2005, pp. 3290-3296)  
[182] Another aspect of the settlement of issues surrounding NSPI=s natural gas agreement is its  
impact upon the long-term receivable. The existing agreement includes a price adjustment clause  
respecting natural gas purchases over a period of three years. Under the clause, the Company pays  
for the natural gas purchases at an agreed upon contract price, but at the end of three years is entitled  
to receive a rebate based on the application of a price cap. The savings achieved as a result of the  
price cap are reflected in the long-term receivable, which has been estimated by NSPI. The  
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Company submits that, if the Board decides to increase the natural gas resale benefit, then there  
should also be a corresponding adjustment in the long-term receivable.  
3.7.2 Submissions - Dr. Stutz and Intervenors  
Dr. Stutz  
[183] In his testimony, Dr. Stutz proposed a different mechanism for the treatment of the natural  
gas resale benefit, if it ultimately exceeds NSPI=s post-settlement estimate of the benefit:  
Finally, let me turn to the Gas Resale Margin. Recent developments discussed in the  
confidential portion of these hearings have led NSPI to increase the benefit from the gas  
resale included in its proposed test year required revenues. The Company has also proposed  
that, to the extent that additional gas resale margins reduce NSPI's actual total fuel expense  
below the amount approved by the Board for inclusion in rates, the difference will, following  
Board direction, be applied to benefit ratepayers.  
The Company's revised estimate of gas resale benefits reflects the uncertainty in the amount  
of gas it may sell and the margin it will earn per unit volume sold. It would be reasonable to  
assume that the Company has taken care not to overestimate the revised benefits included in  
its base rates. It is also reasonable to assume that actual gas resale margins may exceed  
those that the Company proposes to include in its required revenues. Thus, the treatment of  
additional gas margin revenues could be important.  
The Company's proposal for the treatment of additional gas margin revenues does not permit  
the Board to decide now how the benefit of such revenues would be divided between the  
Company and its customers. To provide the Board the opportunity to make that decision, I  
recommend that the Board direct the Company to set up a reserve fund equal to the excess,  
if any, of actual gas resale margins for 2006 above the amount included in rates. The Board  
need not decide how the fund will be used now, nor whether the fund will benefit NSPI, its  
customers, or both. That can be decided in the general rate proceeding to be held in 2006 or  
at whatever time the Board finds it appropriate.  
(Stutz Opening Statement, Exhibit N-244; Transcript, December 2, 2005, pp. 3514-3515)  
Avon  
[184] Avon raises three issues with respect to the incorporation of natural gas costs and resale  
benefits into NSPI=s fuel budget for the 2006 test year. First, it asks the Board to review the  
settlement between NSPI and its natural gas supplier to ensure that the benefits arising under the  
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settlement are allocated fairly between the Company=s shareholders and ratepayers. Avon notes  
that the settlement addressed two issues, namely, compensation to NSPI relating to deliveries of  
natural gas prior to December 16, 2005, and the establishment of a price and supply arrangements  
respecting future deliveries of natural gas. The latter would benefit NSPI=s customers, while the  
former would accrue to the benefit of the shareholders. Avon cautions that the negotiation of both  
items in one settlement raises issues about whether NSPI received additional compensation  
respecting deliveries of natural gas prior to December 16, 2005, at the expense of terms related to  
future pricing of natural gas under the contract.44  
[185] In cross-examination by Robert G. Grant, Q.C., Counsel for Avon, Mr. Tedesco  
acknowledged that there was a relationship between the settlement of issues respecting both past and  
future deliveries of gas:  
... I would characterize that [compensation for deliveries prior to December 16, 2005] as  
absolutely instrumental to receiving the assurances that we did for [future] gas deliveries.  
(Transcript, November 24, 2005, p. 1585)  
[186] Second, Avon also expressed concern about the reasonableness of NSPI=s revised forecast  
for the natural gas resale margin under the negotiated settlement. While Avon acknowledges that  
the forecast based on the November forward price strip may be too optimistic, it stated that NSPI=s  
revised forecast based on the May 11, 2005 forward price strip was unreasonably low. In light of  
44Avon, Confidential Closing Submission, pp. 14-16  
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these two extremes, Avon suggested that the Board establish an amount for anticipated gas revenues  
Abased on its realistic view of the current gas markets@.45  
45Avon, Redacted Closing Submission, p. 18  
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[187] Finally, Avon described NSPI=s proposed refund or deferral account as Aillusory@ because  
any surplus would first be used to offset deficiencies for other fuel types in NSPI=s fuel budget,  
including the imprudence disallowance, before customers would benefit from any improved gas  
margin.46 In Avon=s view, such a mechanism detracts from the punitive nature of an imprudence  
disallowance.  
[188] However, Avon did express support for deferring any surplus gas resale margin, stating that  
any such excess ought to accrue to the benefit of customers either by way of a refund or a reduction  
of future revenue requirements.47  
46Avon, Redacted Closing Submission, p. 13  
47Avon, Redacted Closing Submission, p. 18  
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Consumer Advocate  
[189] The Consumer Advocate highlighted the two suggested methods for dealing with the  
anticipated natural gas resale benefit. In his Closing Submission, the Consumer Advocate suggested  
that one approach would have the Board factor the natural gas resale benefit into NSPI=s fuel  
budget, for the purpose of setting rates. Applying this approach, the Consumer Advocate noted that  
the risk/benefit would lie with the Company=s shareholders, as it should be under rate-setting  
principles. However, the Consumer Advocate submitted that if this method is to be adopted for the  
purpose of setting rates, then the Board should revise upward the gas resale benefit estimated by  
NSPI since, in his view, it is clearly too low.  
[190] In the alternative, the Consumer Advocate concurs with Dr. Stutz=s suggestion that a reserve  
fund be set up to capture any gas resale benefit to the extent it exceeds NSPI=s revised estimate.  
The Consumer Advocate opposes NSPI=s suggestion that any surplus benefit from the resale of  
natural gas should be applied against other fuel costs, including an imprudence finding. Such risks,  
in the opinion of the Consumer Advocate, should properly be borne by the Company=s  
shareholders.48  
48Consumer Advocate, Redacted Closing Submission, pp. 7-8  
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Province  
[191] In its Closing Submission, the Province reiterated its qualified support for a fuel adjustment  
mechanism, noting that the development of a FAM should be undertaken carefully and with  
stakeholder involvement in its design and implementation. The Province suggested that steps should  
be taken towards the implementation of a FAM once NSPI has hired an in-house coal expert and  
made its procurement decision-making process more transparent.49  
49Province, Redacted Closing Submissions, pp. 21-22  
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[192] With respect to NSPI=s suggested mechanism for dealing with any excess natural gas resale  
benefit, the Province suggests that a better approach is for the Board to incorporate the anticipated  
revenues from gas resales into the Company=s total fuel budget, using the best information available  
to the Board with respect to the likely pricing of natural gas in the 2006 test year. The Province is  
reluctant to adopt the mechanism proposed by NSPI because, in its view, the natural gas resale  
benefit to be realized is likely to exceed that projected by NSPI, given the most up-to-date forward  
price strip available to the Board at the conclusion of the hearing. The Province observes that the  
difference could be approximately $40 million if the November 2005 forward price strip (rather than  
the May 2005 forward price strip) accurately predicts the state of the natural gas market in the test  
year. In that event, the Province notes that ratepayers would be making a considerable prepayment  
against future rates, or possible rebate, something which current ratepayers facing a proposed double  
digit increase should not be asked to absorb.50  
CME  
[193] The CME opposes NSPI=s proposal to offset any surplus natural gas resale benefit against a  
shortfall in its overall fuel budget and against any imprudence disallowance. In its Closing  
Submission, the CME challenges NSPI=s proposed assignment of risks between NSPI and its  
customers with respect to the fuel budget:  
41. The present lack of a fuel clause is not relevant and it is worthy of note that until fuel  
procurement has achieved a level of sophistication in design and execution satisfactory to  
NSPI, the Board and ratepayers a fuel clause or fuel adjustment mechanism (FAM) is unlikely  
to be implemented because it has to be a proper balancing of the risk.  
50Province, Redacted Closing Submissions, pp. 19-21  
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110  
42. Also, it is the position of the CME that risk should not be symmetrical as indicated by  
Mr. Tedesco. NSPI receives a good rate of return. Encapsulated in that rate of return is a  
premium for risk. It has in the past, and should be in the future, be responsible for the  
operations of the business and the risks that go with it including fuel procurement. It is the  
beneficiary of a known rate of return (notwithstanding an imposed limited). The relationship  
of risk is not symmetrical. The impetus for ratepayers approving a FAM or such other  
mechanism is for the benefit of predictability, leveling of fluctuations and in some cases,  
sharing of risk but it is not one of symmetry. Any acceptance under a FAM or such other  
mechanism is based on the good operations of such a mechanism. Any other shift would  
remove the incentive from the operator.[Emphasis added in original]  
(CME, Redacted Closing Submission, p. 23)  
SEB  
[194] SEB also opposed the mechanism proposed by NSPI. In its Confidential Fuel Related  
Argument, SEB submitted that NSPI=s gas resale benefit should be set based on the November 2005  
forward price strip filed in Undertaking U-58. SEB stated that NSPI=s forecast for the gas resale  
benefit (based on the May 2005 forward price strip) is not reasonable because there is more current  
information filed with the Board. SEB argued that it would be unreasonable to allow NSPI to apply  
any surplus gas resale benefit to offset increases in its remaining fuel budget, describing as patently  
unreasonable NSPI=s suggestion that any such surplus gas resale benefit should also be used to  
offset an imprudence disallowance.51  
[195] SEB reiterated its position that customers should get the immediate benefit of the gas resale  
margin, rather than deferring the benefit to a future test year:  
51SEB, Confidential Fuel Related Argument, pp. 50-51  
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In its Closing Argument NSPI attempts to paint the picture of deferring the potential value of  
the gas contract as a good thing, so as to possibly alleviate the burden of a future rate  
increase. As NSPI=s two largest customers, SEB have no interests nor do they think it is  
appropriate to delay, a potential benefit so as to alleviate future rate increases. This is  
particularly so in the face of the extraordinary increase proposed for SEB by NSPI in this  
proceeding. SEB=s position is that customers should get the full benefit of the natural gas  
resale margin, and that this should be done by way of application of the current third party  
available indices.  
(SEB, Confidential Fuel Related Rebuttal Argument, p. 17)  
[196] SEB encouraged the Board to ensure that it is satisfied with the accounting treatment of the  
natural gas contract and the long-term receivable contained in NSPI=s evidence. Further, SEB  
expressed concern that, following the announcement of the natural gas settlement, Undertaking U-76  
showed a greater long-term receivable at the end of 2005 than the amount shown in Appendix A of  
the original filing, implying that 2005 purchased gas costs were overstated compared to the  
contractual cap. SEB suggested that this demonstrates an unfair allocation of the settlement to  
shareholders and that the overstatement should be available to customers of NSPI as a refund.52  
3.7.3 Findings  
[197] As a result of the settlement reached between NSPI and its natural gas supplier, the Company  
expects to achieve better results on the resale of its natural gas than originally forecast when it filed  
its application on July 5, 2005.  
[198] There are various issues which arise with respect to the natural gas component of the fuel  
budget, including: 1) what price should be attributed to the commodity and what volume can NSPI  
52SEB, Confidential Fuel Related Argument, p. 53  
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expect to receive, in order to determine what natural gas resale benefit should be incorporated into  
NSPI=s total fuel budget; 2) whether the Board should approve a deferral mechanism as proposed by  
NSPI or, alternatively, a reserve fund, as proposed by Dr. Stutz; 3) whether the benefits of the  
natural gas settlement were appropriately allocated between NSPI=s shareholders and customers;  
and 4) whether the long-term receivable should be adjusted to reflect the Board=s findings  
respecting the gas resale benefit.  
[199] The first issue requires the Board to determine the amount of the natural gas resale benefit to  
be incorporated into NSPI=s total fuel budget.  
[200] Based on its review of the record, the Board is satisfied that NSPI=s estimated impact of the  
settlement (increasing the benefit by $22.6 million) is too conservative, while the revised estimate  
based on the November 2005 forward price strip (increasing the benefit by $64.1 million) is too  
optimistic. Having regard to the highly volatile nature of the natural gas market, and the potentially  
significant impact that this amount can have on NSPI=s fuel budget, the Board recognizes that  
caution is required. Nevertheless, weighing the relevant evidence, virtually all of which is  
confidential, the Board finds that it is reasonable to adopt a gas resale benefit $35.8 million higher  
than that contained in the original filing of July 5, 2005, thereby decreasing NSPI=s original fuel  
budget by the same amount. The Board notes that this results in a gas resale benefit for 2006 which  
is very comparable to the gas resale benefit actually realized by NSPI in each of 2004 and 2005.  
The Board sees nothing in the material produced at the hearing which would indicate that NSPI will  
not be able to achieve at least an equal gas resale benefit in 2006.  
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[201] The determination of the natural gas resale benefit impacts upon the Board=s consideration  
of the deferral mechanism proposed by NSPI and the reserve fund suggested by Dr. Stutz.  
[202] While the Board recognizes that NSPI=s proposed deferral mechanism is not, strictly  
speaking, a fuel adjustment mechanism (AFAM@), its effect is similar, in some respects, in terms of  
its potential impact upon NSPI=s proposed fuel budget.  
[203] Following the Board=s review of the evidence and submissions, it considers that there are  
various issues which detract from the approval of a deferral mechanism or reserve fund at this time.  
[204] In its March 31, 2005 decision, the Board refused to incorporate a FAM proposed by NSPI:  
[131] The Board shares the views of the intervenors with respect to the FAM proposed by  
NSPI. The Board recognizes that FAMs exist in many other jurisdictions and can, potentially,  
be a positive and useful regulatory tool. However, in view of the Board's findings with respect  
to imprudence and inadequacies in NSPI's fuel procurement practices, it would be quite  
inappropriate to approve a FAM at this time. The Board does not believe it is in the public  
interest to transfer the risk of fuel price volatility to ratepayers when NSPI's ability to achieve  
the best possible fuel price is in question.  
[132] Further, the Board is of the view that transferring such risk from shareholders to  
ratepayers could diminish the incentive for NSPI to quickly and thoroughly improve its fuel  
procurement process. This is particularly the case since the FAM proposed by NSPI would  
transfer 100% of the risk to ratepayers. Accordingly, the Board rejects the proposed FAM.  
Further, in view of the Board's concerns in this area, should NSPI apply for approval of a  
FAM in future, the Board will order an independent audit of NSPI's overall progress and  
performance with respect to the necessary fuel procurement improvements. This audit would  
include, as recommended by Liberty, "... a more detailed examination..." of fuel and energy  
transactions and relationships with affiliates and would form part of the evidence the Board  
would consider in any future FAM application.  
(Board Decision, March 31, 2005, para. 131-132)  
[205] While the Board has concluded in this decision that NSPI has made significant improvements  
in its fuel procurement procedures, the Board still has reservations about incorporating, at this time,  
an adjustment mechanism with respect to NSPI=s fuel budget. As noted above, there remain  
elements of the Company=s Fuel Procurement Policies and Procedures Manual which require  
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improvement, most notably as it relates to natural gas, and improving the transparency of its  
decision-making in relation to its fuel. In these circumstances, the Board is reluctant to vary from its  
current regulatory practice of setting the fuel budget.  
[206] There are further reasons for the Board=s conclusion. First, Dr. Stutz=s proposal  
contemplates an adjustment mechanism which is limited to variances in one type of fuel, rather than  
the range of fuel types comprising NSPI=s portfolio. In the view of the Board, any such adjustment  
mechanism, if adopted, should apply to all fuel types collectively. Further, NSPI=s proposal would  
allow it to recover any shortfall in its overall fuel budget, including imprudency. In the opinion of  
the Board, this is not an equitable proposal for customers in that they would not likewise benefit if  
NSPI were to achieve better results than the fuel budget approved by the Board. In other words,  
NSPI=s shareholders would be afforded the opportunity to offset any costs above the approved  
budget for 2006, while customers would not be entitled to benefit if the Company was able to  
achieve better results in its remaining fuel budget than currently forecast. Moreover, setting the  
natural gas resale benefit at the level proposed by NSPI, accompanied by either the deferral  
mechanism proposed by NSPI or the reserve fund proposed by Dr. Stutz, would, in the opinion of  
the Board, provide little incentive to NSPI to improve upon the forecasted benefit.  
[207] Furthermore, and most importantly, in a test year where customers are facing a significant  
rate increase, the Board is loath to defer any potential benefits from the gas resale benefit to a future  
test year.  
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[208] Accordingly, the Board concludes that the gas resale benefit should be increased by $35.8  
million above that contained in NSPI=s original application dated July 5, 2005, and that no deferral  
mechanism or reserve fund should be implemented at this time.  
[209] Avon and SEB asked the Board to consider whether the benefits of the natural gas settlement  
between NSPI and its supplier were appropriately allocated between the Company=s customers and  
shareholders. As noted by Avon in its Redacted Closing Submission, the settlement addressed two  
issues, namely, compensation to be received by NSPI for deliveries of natural gas from its supplier  
prior to December 16, 2005, and the establishment of a price and improved supply arrangements  
respecting future deliveries of natural gas, but only to the extent that gas is available to the supplier.  
Customers will benefit from a fair price and improved supply arrangements for future deliveries  
which likely will be resold into the market with the revenue applied against NSPI=s fuel budget. On  
the other hand, shareholders will benefit from compensation for deliveries of natural gas from the  
supplier prior to December 16, 2005.  
[210] As noted previously, the settlement between NSPI and its supplier was reached in the midst  
of the hearing. The terms of the settlement were filed in a confidential exhibit. The Board concurs  
with Avon and SEB that NSPI must satisfy the Board that the benefits of the settlement were fairly  
allocated between the customers and shareholders.  
[211] The Board observes that the dispute between NSPI and its natural gas supplier involved  
complex contractual issues. The two parties were both sophisticated entities, each of which thought  
that their respective positions were sufficiently strong to lead them to pursue a ruling from an  
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independent arbitration panel. Subsequent to the arbitration, but before the arbitration decision was  
issued, the parties reached their agreement.  
[212]  
In commercial disputes like the one under consideration, there is never any guarantee of  
success. A claim may be denied by the court or tribunal, or decided in a manner not anticipated by  
either party to the dispute. Both NSPI and its supplier no doubt made some compromises in  
reaching the terms of settlement.  
[213] The Board is satisfied from its review that the settlement clearly involved the two issues  
identified by Avon. While the shareholders of NSPI benefitted from a lump sum payment,  
representing compensation for deliveries of natural gas from the supplier prior to December 16,  
2005, the settlement also benefitted customers because NSPI negotiated terms with respect to the  
supply arrangements and price of natural gas for future deliveries. This will benefit NSPI customers  
in 2006 and beyond because it provides greater certainty with respect to price and volume. In the  
absence of this negotiated settlement, it is not possible to determine with any certainty whether NSPI  
would have been successful on either of these two points at arbitration.  
[214] It is difficult to ascertain whether the benefits from the settlement were scrupulously  
allocated between the shareholders and the customers of NSPI. However, the Board is satisfied that  
the issues relating to deliveries of natural gas prior to December 16, 2005 and the fixing of future  
prices and supply arrangements were inextricably related to one another such that it would not have  
been practical or reasonable to reach a settlement between the parties without addressing both issues  
concurrently. The Board is satisfied that NSPI, to the extent possible, attempted to segregate those  
issues in its negotiations with the supplier. It is very possible that an arbitration decision respecting  
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issues of pricing and volume for future gas deliveries could have been less favourable for NSPI  
customers than that achieved under the negotiated settlement.  
[215] Having reviewed the terms of the negotiated settlement, the testimony related to it, and the  
submissions of the parties, the Board is persuaded that the settlement reached with the supplier  
benefits NSPI=s customers and that there was a fair and reasonable allocation of the benefits  
accruing under the settlement between shareholders and customers.  
[216] In its Compliance Filing, NSPI should address the Province=s concerns with respect to the  
long-term receivable, as set out in paragraph 68 of its Closing Submission.  
3.8  
Fuel Costs  
3.8.1 Submissions - NSPI  
[217] The primary issue is the accuracy of NSPI=s original fuel forecast. NSPI, in  
calculating the cost to be ascribed to coal required for the test year but not purchased at  
the time of the application, based its value on the forecast prepared by Hill & Associates. A  
number of the intervenors took the position that it would have been more appropriate to  
price the uncommitted coal using EVA=s forecast, which was generally lower than Hill=s.  
In the eyes of the intervenors at least, the EVA forecast was also more accurate, since it  
correctly predicted the downward trend in coal prices which subsequently occurred.  
[218] With respect to the forecasts, NSPI argued that it has been difficult to forecast fuel prices  
with any degree of accuracy in the past few years. In this regard, NSPI emphasized that there was  
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no evidence in the 2005 rate case predicting either the magnitude or the duration of the price spike  
which occurred.53  
[219] NSPI continued:  
Nevertheless, in the current case, intervenor consultants now purport to see the global coal  
market clearly and have concluded that it is falling. They hold strong opinions on what price  
forecast NSPI should use and which one it should not use. This certainty about 2006 is less  
impressive, when one is reminded of the collective failure of these consultants to predict the  
magnitude and duration of the market price event that started in late 2003 and has continued  
to this date.  
. . .  
Certain intervenors asked why NSPI did not use the lowest possible forecast price available  
to estimate its balance of the year prices. The answer is simple. The EVA forecast was not  
offered as an alternative to Hill. In fact, until February 2005, EVA had not published a forecast  
of South American coal in its FUELCAST/COALCAST Service. EVA recommended that NSPI  
use the Hill forecast because Hill & Associates has an international reputation with respect to  
South American coal. It publishes multiple multi-client reports on this coal region including the  
annual forecast report upon which NSPI relied.  
(Exhibit N-153, p. 11)  
[220] NSPI stated that:  
... Now that the coal market price is below the budget amount, several of the intervenors  
would like an adjustment to all uncommitted tonnes at the time of the Application. This is  
similar to a request in the 2004 Application that NSPI adjust its foreign exchange  
requirements for un-purchased coal due to the strengthening of the Canadian dollar. As with  
coal, NSPI has policies regarding currency hedging. The Board did not accept this  
recommendation, which suggests a recognition that that the continued hedging was  
appropriate and an ex post facto adjustment related to the decline in the foreign exchange  
was inappropriate for committed hedges. The same philosophy is appropriate with respect to  
solid fuel hedges.  
(Exhibit N-153, p. 15)  
[221] In its Closing Argument, NSPI submitted:  
It has been the practice of the Board to set rates based upon the forecasts as filed, provided  
they are reasonable. The evidence demonstrates that NSPI used reasonable forecasts,  
53Exhibit N-153, pp. 11-12  
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professionally prepared by experts in the field. Prices for committed and uncommitted fuel in  
the NSPI application are accurate and proper for rate-making purposes.  
Nova Scotia Power has relied upon a forecaster with an international reputation. No other  
party to the proceeding offered an alternative forecast that provided comparable data with  
sufficient documentation so as to be a suitable substitute for the Hill forecast.  
. . .  
The evidence shows that the overall fuel costs anticipated by NSPI for 2006 are appropriate,  
even in light of volatile fuel markets. As indicated in NSPI=s response to U- 29, changes in  
the cost of one fuel are just as likely to be offset by changes in the cost of another. ...  
(NSPI, Redacted Closing Argument, pp. 18-19)  
[222] In its Reply to Closing Argument, NSPI maintained that the overall fuel budget, as  
filed, represents a realistic number, notwithstanding that parts of the forecast may be higher  
or lower than the proposed budget:  
The fuel budget contained in NSPI=s 2006 application is based upon the best information  
available at the time of the application, in accordance with the ratemaking principles of this  
jurisdiction. No Intervenor offered into evidence an alternative price forecast which contained  
any detail or applicability to be useful to the Board. Ms. Medine completely explained that the  
EVA forecast of quarterly spot prices is not an appropriate forecast for NSPI=s 2006 fuel  
costs. The evidence confirmed that parts of NSPI=s forecast may be higher or lower than the  
budget but overall represent a realistic number.  
Further, NSPI customers are protected from over recovery in two ways. First, NSPI is  
capped with respect to earnings should fuel costs come in lower than expected. Second,  
NSPI customers could receive a refund if natural gas revenues are higher than forecast  
subject to NSPI recovering its fuel costs.  
(NSPI, Redacted Reply to Closing Argument, p. 7)  
3.8.2 Submissions - Intervenors and Liberty  
SEB  
[223] In its Final Confidential Fuel Related Argument, SEB submitted that:  
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... NSPI=s fuel forecast should be adjusted to take account of the fact that NSPI is utilizing a  
very high forecast for 2006 imported ... coal tonnage which was not committed at the date of  
the application. NSPI utilized the March 2005 Hill & Associates Forecast notwithstanding that  
it was substantially higher than the forecast for 2006 available to NSPI from its consultants  
EVA.  
(SEB, Final Confidential Fuel Related Argument, p. 38)  
[224] Mr. Gubbins adjusted the balance of the uncommitted coal, to reflect the difference in the  
price forecast prepared by Hill & Associates as compared with the forecast prepared by Mr.  
Gubbins= firm, McCloskey Group. Mr. Gubbins stated that the Hill price forecast for 2006 was too  
high. The adjustment calculated by Mr. Gubbins is $9.45 million.  
[225] According to SEB, it is clear from the record that the current prices for coal support the use  
of a lower forecast. As an example, SEB quoted from Mr. Gubbins= opening statement in which he  
suggested that prices on November 11, 2005, as reported in the McCloskey Coal Report, were  
significantly lower than the prices used by NSPI in its forecast.54  
AVON  
[226] Avon, in its Closing Submission, contended that the use of the Hill forecast was  
inappropriate. This is because the prices forecast by Hill were too high and thus overstated the fuel  
requirements for 2006.  
[227] Avon argued that the Hill forecasts are demonstrably wrong, and A... fail to reflect the  
cyclicality in the international coal market which all experts agree exists,. . . and this Board should  
be wary about using long-term forecasts for near term coal commitments. Certainly, even NSPI=s  
54SEB, Final Confidential Fuel Related Argument, p. 39  
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consultants Ms. Medine and Daniel Walton, agreed that shorter term forecasts are more accurate  
than long as a general rule.@55  
55Avon, Redacted Closing Submission, pp. 8-10  
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[228] Should the Board agree that the Hill long-term forecasts are inappropriate to use for the test  
year, then Avon suggested that there are several options which the Board could use. One option is  
for the Board to take the uncommitted volume as of the date that NSPI filed its rate case and  
substitute a more representative cost estimate based on either the EVA forecast, as Dr. Raschke did,  
or the McCloskey forecast, as Mr. Gubbins did. The impact of using the EVA forecast, according to  
Dr. Raschke, would be to reduce the fuel budget by approximately $28.2 million. Using the  
McCloskey forecast reduces costs by about $10 million.56  
[229] Avon also indicated that:  
The Board may account for commitments made since the rate filing and replace the balance  
of the uncommitted tonnages and options with the appropriate Aplug@ number - whether EVA  
forecast or McCloskey. Undertaking U - 29 sets out NSPI=s most current volumes, replacing  
its forecasted figures with committed prices...  
(Avon, Redacted Closing Submission, p.11)  
[230] In its Closing Submission, Avon presented a calculation prepared by Dr. Raschke which,  
according to Avon, demonstrates that A... even if all of NSPI=s current contracts are accepted the  
coal costs claimed for 2006 are still too high by at least $14.8 million...@57  
[231] Avon maintained that AIt would be inappropriate for NSPI to have the benefit of a  
unreasonably high cost per MMBtu when it is based on a demonstrably wrong long-term forecast  
and when its own contracts subsequently entered into show this.@58  
56Avon, Redacted Closing Submission, pp. 10-11  
57Avon, Confidential Closing Submission, pp. 11-12  
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[232] In its Reply Submission, Avon revised its proposed adjustment to the fuel costs from the  
$14.8 million figure previously recommended to a recalculated figure of $21.3 million. Avon stated:  
At our request, Dr. Raschke reviewed the transcripts of the NSPI fuel panel and using the  
information regarding the current contracts and their options, recalculated the savings to  
NSPI from its contracts entered into since May 1, 2005, assuming the negative exercise of  
the contract options. The recalculated figure is $21,277,636 versus his previous assessment  
of $14,768,533. His revised calculations are appended as Appendix AA@.  
NSPI=s fuel budget is not reasonable; it is unrepresentative and the forecasted coal cost  
number is demonstrably wrong. Avon respectfully submits that the Board ought to disallow  
$21.3 million from NSPI=s 2006 fuel budget based on the fact that NSPI has entered into  
lower priced contracts replacing its uncommitted volumes forecasted at higher levels. If the  
fuel budget is approved as stated, it would offer a windfall to NSPI shareholders, who would  
benefit from the fact that contracts have been committed at lower prices.  
(Avon, Redacted Reply Submission, p. 6)  
Province  
58Avon, Confidential Closing Submission, pp. 11-12  
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[233] The Province, in its Closing Submission, took no position concerning whether NSPI=s  
original fuel price forecasts were appropriate. However, it stated that the fuel budget should be  
revised because it no longer accurately reflected the 2006 fuel costs likely to be incurred.59  
[234] The Province pointed out that a number of circumstances, which have occurred since the  
original test year estimates were prepared, cause the original projections to be less relevant to the  
2006 test year. These events include savings achieved on coal contracts entered into since the  
application was filed, at prices less than original forecast, and HFO prices which have increased over  
those originally forecast by NSPI. The Province noted that:  
... Liberty has taken the position that the gains that NSPI is likely to realize in improvements  
to its solid fuel forecasts will be offset by the likely higher HFO prices. In Liberty=s view,  
these factors amount to a wash, though no specific calculations were provided to support that  
opinion.  
(Province, Confidential Closing Submission, pp. 17-18)  
[235] The Province made no specific recommendation with respect to this issue.  
Liberty  
59Province Redacted Closing Submission, p. 15  
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[236] Liberty stated, in its Direct Evidence, that NSPI=s estimate of solid fuel costs for the 2006  
test year A... has turned out to be too high, as recent NSPI purchases have reduced the amount of  
uncommited tonnages and at prices less than NSPI had estimated.@60  
[237] In its pre-filed evidence, Liberty concluded that there should be a reduction of $10,378,294  
in fuel expense for the 2006 test year, because NSPI... Ahas been able to secure at lower than  
estimated prices much of the fuel that was uncommitted at the time of the Company=s filing.@61  
Liberty explained that these reduced costs related to low sulphur coal and petcoke.  
60Exhibit N-97, p. 8  
61Exhibit N-97, p. 11  
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[238] In its opening statement at the hearing,62 Liberty indicated that it was no longer  
recommending the reduction in question. Liberty stated that, because the net effect of price changes  
in heavy fuel oil (HFO), petcoke and coal, when the currently uncommitted fuel is eventually  
acquired, is uncertain and cannot be quantified at this time, it believes that the change should be  
treated as a wash. During cross-examination, Mr. Grant asked Liberty to confirm that A... you are  
comfortable with the concept that whatever savings will be made on the remaining uncommitted  
solid fuel, that will be offset by increases in prices in HFO over budget@. Liberty replied that A...  
We=re comfortable that the net of the changes on all solid fuel and HFO would be an offset to  
current budget.@63  
3.8.3 Findings  
[239] The Board observes that Undertaking U-29, filed by NSPI on November 28, 2005, provided  
an estimate of the effects of commitments to date in HFO, coal, and petcoke, as compared with the  
forecast in the original filing. Undertaking U-29 indicated that reductions in cost were realized on  
the coal and petcoke commitments entered into since the application was filed, while increases were  
experienced in the cost of HFO. As a result of these changes, NSPI asserted its total fuel cost has  
62Exhibit N-214  
63Transcript, November 29, 2005, p. 2338  
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increased from the $478.9 million reflected in the filing, to $481.7 million, an increase of $2.8  
million to November 28, 2005, the date of the Undertaking.  
[240] After considering the evidence in relation to this matter, including the issue of volume  
options, the Board is not persuaded that there should be any adjustment to the coal, petcoke, and  
HFO portions of the fuel budget, and agrees with Liberty=s recommendation in this respect.  
[241] Accordingly, the Board sets NSPI=s fuel budget for the test year as follows:  
Total Estimated Fuel Costs as per original filing  
$478,900,000  
Less Additional Natural Gas Resale Benefit  
determined by Board  
(35,800,000)  
( 2,300,000)  
(15,700,000)  
$425,100,000  
Less PTMT Disallowance  
Less Imprudence Disallowance  
Approved Fuel Budget  
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4.0  
4.1  
FINANCE  
Return on Equity  
[242] The capital to finance NSPI=s generating, transmission, distribution and other assets comes  
from equity investors, as well as through the issuance of debt. The return on equity (the AROE@)  
earned by the Company represents the income earned by the equity investors. In the 2005 rate  
decision, the Board approved an ROE at 9.55% for the purpose of setting rates, with an earnings  
range set at 9.30% to 9.80%. While NSPI contends that this ROE is very close to that granted  
elsewhere in Canada for utilities which do not face comparable fuel and generation risks borne by  
the Company, NSPI is not proposing any change with respect to ROE in the present case,  
considering the recent decision by the Board on this issue.  
[243] The proposed ROE was not the subject of comment by any of the intervenors at the hearing.  
While the NDP Caucus raised the issue of an appropriate ROE in its Closing Submission, there was  
no evidence to support a change in the ROE.  
4.1.1 Findings  
[244] The Board is satisfied that the ROE should be maintained at 9.55% for the purpose of setting  
rates, with the earnings range set at 9.30% to 9.80%.  
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4.2  
Capital Structure  
[245] In the 2005 rate decision, the Board also approved an increase in the common equity ratio for  
ratemaking purposes from 35% to 37.5%. This increase, which was supported by a majority of the  
intervenors in the 2005 rate case, was considered desirable by the Board to strengthen the  
Company=s balance sheet in the current economic climate and also reflective of Emera=s common  
equity ratio. For the 2006 test year, NSPI proposes that the common equity ratio for ratemaking  
purposes continue at 37.5%. The proposed common equity ratio was not the subject of comment by  
any of the intervenors at the hearing.  
4.2.1 Findings  
[246] The Board is satisfied that the common equity ratio for ratemaking purposes should be  
maintained at 37.5%.  
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5.0  
5.1  
RATE BASE  
Overview  
[247] In the 2005 rate decision, the Board noted a consensus among the intervenors that NSPI  
should change the way it calculates the rate of return to a return on rate base methodology.  
Accordingly, the Board approved a change to NSPI=s long-standing practice of calculating its return  
on the equity portion of total capitalization and directed that NSPI use a return on rate base  
methodology for its next rate application. The Board further directed NSPI to file in its next rate  
application all information and explanations necessary to enable the Board and intervenors to clearly  
understand the basis of NSPI=s calculations. The Board noted that NSPI should also reconcile its  
calculations of return on rate base to calculations using the return on equity methodology.  
[248] The main issue which arose from the adoption of the rate base methodology was calculating  
the cash working capital (ACWC@) allowance. Kathleen C. McShane, Senior Vice-President of  
Foster Associates, Inc., filed evidence and testified at the hearing on behalf of NSPI with respect to  
the determination of the CWC allowance. In NSPI=s Rebuttal Evidence, she defined CWC  
allowance and how it is typically determined:  
The cash working capital allowance reflects the average amount of capital provided by  
investors above and beyond investments in plant and other separately identified rate base  
items, including other components of working capital (e.g., materials and inventory), that  
bridges the gap between the time expenditures are made to provide service and the time  
payment is received for that service. The rate base in its entirety represents the amount of  
investor-supplied capital required to provide service; the cash working capital component  
needs to be compatible with the determination of the other elements of the rate base.  
The cash working capital allowance is typically measured using a lead/lag study. The  
purpose of a lead/lag study is to provide a measure of the amount of investor funds used in  
sustaining utility operations from the time expenditures are made until the time payment is  
received.  
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A lead/lag study recognizes that the utility renders service prior to receipt of payment from  
ratepayers, but that there is generally also a delay in payment for goods and services  
acquired by the utility. The lead/lag study analyzes transactions throughout the year to  
determine the net lag days between the date service is rendered and payment is received  
(revenue lag), and the time lag between the time expenditures are recorded and payment is  
made for such expenditures (expense or payment lag). In some instances, revenue may be  
received prior to payment for the related expense. In that case, there will be a net lead (or  
alternatively, a negative net lag).  
(NSPI, Rebuttal Evidence, Exhibit N-153, pp. 58-59)  
[249] NSPI projects that it will require $29.4 million to be included in the rate base for CWC  
allowance in the 2006 test year.64  
[250] Ms. McShane described NSPI=s methodology of determining its CWC allowance as an  
approach focusing on the operating or Aabove-the-line@ expenses of NSPI. She states that this  
approach excludes non-cash expenses (e.g., depreciation) and return on capital.65  
[251] Several intervenors have raised issues with the calculation of the CWC allowance.  
Specifically, they have questioned NSPI=s exclusion of items like HST, securitized accounts  
receivable, interest expense and preferred dividends. They have also challenged some of the  
lead/lag assumptions made by NSPI. Further, at least one intervenor has questioned NSPI=s  
reconciliation of its return on capitalization versus its return on rate base, as it believes the result  
should be the same in each case. These issues are examined, in turn, below.  
64NSPI Application, Exhibit N-2, Appendix A, Table 17  
65NSPI Rebuttal Evidence, Exhibit N-153, p. 61  
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5.2  
HST  
5.2.1 Submissions - NSPI  
[252] In its original application, NSPI did not include HST in its calculation of the allowance for  
CWC.66  
[253] In his testimony, Greg Blunden, NSPI=s General Manager of Finance, indicated that the  
Company=s approach was to include only operating expenses and that it excluded items like HST  
and payroll taxes that may flow through their accounts. Stating that there are only a couple of days  
difference between the collection and remitting of HST, it was felt that the exclusion of HST would  
have no material impact upon the CWC requirement.67  
[254] During questioning by Board counsel, Mr. Blunden was asked to calculate the impact of the  
HST upon CWC. In its response to Undertaking U-35, NSPI calculated the Apossible impact@ of the  
timing difference between the collection and remittance of net HST, concluding that it could reduce  
the cash operating working capital by $4.4 million for the 2006 test year. Multiplying this amount  
66Exhibit N-2, Appendix A, Table 17  
67Transcript, November 22, 2005, p. 1010  
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by the weighted average cost of capital (i.e., 8.21%), the total revenue requirement would be reduced  
by $400,000.68  
68NSPI, Undertaking U-35, Attachment 1  
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[255] In its Closing Argument, NSPI confirmed that the revenue requirement would be reduced by  
$400,000 if the CWC were to be adjusted for the collection and remittance of HST. However, it  
added that if the rate base is to be adjusted in this fashion, then other adjustments to the rate base  
should also be made for items like the 2005 Q1 tax deferral and the increase in the long-term  
receivable.69  
5.2.2 Submissions - Intervenors  
[256] In his Direct Evidence, Mark Drazen, who appeared on behalf of Avon, submitted that HST  
should be included in the determination of CWC allowance.  
[257] On the assumption that HST must be remitted within 30 days following the end of the month  
in which it is collected, Mr. Drazen determined that NSPI had use of the money for 45 days on  
average (15 days in the month of collection plus 30 days thereafter) or 12.3% of the year. Based on  
the net HST remitted in the amount of $75.7 million,70 Mr. Drazen determined that the CWC  
allowance would be reduced by $9.3 million ($75.7 million x 12.3%).71  
69NSPI, Redacted Closing Argument, p. 77  
70Identified by NSPI in response to Avon IR-54, Attachment 1  
71Drazen, Pre-filed Evidence, Exhibit N-95, p. 9  
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[258] While Avon acknowledged, in its Closing Submission, that Ms. McShane was not involved  
in NSPI=s initial calculation of the CWC allowance, it noted that she did not identify HST for  
inclusion in the lead/lag study in her rebuttal testimony filed on behalf of NSPI.72  
[259] Mr. Grant cross-examined Ms. McShane on the inclusion of HST during the hearing,  
challenging her on this issue relative to her pre-filed evidence in a recent Hydro Quebec rate hearing  
in which she identified HST as an appropriate item for inclusion in the CWC allowance. However,  
it was not identified in NSPI=s application.73 Further, she acknowledged that Newfoundland and  
Labrador Hydro, a client on whose behalf she testified during their 2001 rate application, included  
HST in its lead/lag study, reducing the CWC requirement for that utility.74 She also agreed HST is  
typically included in lead/lag studies.75  
72Avon, Redacted Closing Submission, para. 131-133; McShane, Rebuttal Evidence,  
Exhibit N-153, p. 58  
73Hydro Quebec Pre-filed Evidence, Exhibit N-173, p. 6; Transcript, November 22, 2005, p. 970  
74Exhibit N-174, pp.4-5; Transcript, November 22, 2005, p. 973  
75Transcript, November 22, 2005, p. 967  
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5.2.3 Findings  
[260] Based on its consideration of this matter, it appears that the issue to be determined by the  
Board relates to the extent of the HST=s impact upon the CWC allowance, rather than a question of  
its exclusion from the CWC. While HST was not originally included by NSPI in the determination  
of its CWC requirement, it appears from the testimony of Mr. Blunden that its exclusion was related  
to the belief that it would not have a material impact upon the determination of the CWC  
requirement.76  
[261] The Board concurs with Mr. Drazen that HST should be included in the determination of the  
CWC requirement. Inherent in this finding is a recognition that the Company does have use of the  
money between the time it is collected from customers and the time it is ultimately remitted to  
government. This treatment of the HST also appears consistent with the treatment afforded to HST  
in other jurisdictions such as Quebec and Newfoundland and Labrador, as acknowledged by Ms.  
McShane in cross-examination.77 Further, the Board notes Ms. McShane=s testimony relating to  
76Transcript, November 22, 2005, p. 1010  
77Transcript, November 22, 2005, p. 967  
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Hydro Quebec to the effect that Hydro Quebec=s methodology to determine cash working capital  
focuses on operating or Aabove-the-line@ expenses.78  
78Hydro Quebec Pre-filed Evidence, Exhibit N-173, p. 7  
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[262] Moving beyond the threshold of determining that HST is appropriately included in the CWC  
allowance, NSPI and Avon differ upon the magnitude of its impact. Using information provided by  
NSPI in response to Avon IR-54, Attachment 1, Mr. Drazen calculated the reduction of CWC  
allowance as being $9.3 million. NSPI, on the other hand, calculated the reduction of the CWC  
allowance as only $4.4 million, resulting in a reduction of the revenue requirement by $400,000.79  
The Board observes that NSPI did not cross-examine Mr. Drazen during the hearing with respect to  
his calculation of the HST=s impact upon the CWC allowance. According to Mr. Blunden, the  
distinction between the two methodologies focuses on the revenue lag, i.e., Mr. Drazen assumed the  
HST is not remitted until after it is collected from customers, while NSPI undertook its analysis on  
the basis that HST remittances are triggered based on when customers are invoiced.80  
[263] Upon reviewing this matter, the Board notes that NSPI, in calculating the working capital  
impact of including an adjustment for the HST, based its calculations on the model employed by  
Newfoundland and Labrador Hydro. The model employed by NSPI calculates the payment lag for  
each type of the expenditures on which NSPI pays HST, as well as for the customer billing on which  
NSPI collects HST. The Board believes this is a realistic manner of calculating the HST impact on  
CWC and, accordingly, accepts NSPI=s calculation of $400,000 as a reduction in the 2006 revenue  
requirement.  
79NSPI Undertaking U-35  
80Transcript, November 22, 2005, pp. 1009-1010; see also Avon IR-54  
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5.3  
Interest Expense and Preferred Dividends  
5.3.1 Submissions - NSPI  
[264] On behalf of NSPI, Ms. McShane stated that interest expense and preferred dividends should  
not be included in the determination of CWC allowance. In her view, the determination of CWC  
should focus on operating or Aabove-the-line@ expenses of NSPI, to the exclusion of non-cash  
expenses (e.g., depreciation) and operating income (i.e., return on capital). She submitted that any  
lead/lag study which includes interest expense must also include all sources of investor supplied  
funds, such as allowances for depreciation expense and return on equity. She stated that  
incorporating interest expense and preferred dividend payments into the CWC requires the adoption  
of a broad or Aglobal@ approach to measuring the full extent to which investors finance the revenue  
requirement of the Company. In such instances, she argued that leads and lags on all elements of the  
return of, and on, capital must be taken into account. In her submission, the inclusion of interest and  
preferred dividend payments, to the exclusion of depreciation expense and common equity return, is  
equivalent to Acherry-picking@, which results in an understatement of the actual CWC  
requirement.81  
[265] In support of her position, Ms. McShane relies, in part, on the rejection of the Aglobal@  
approach by other regulators in Canada, including the Régie de l=Énergie du Québec. She cites two  
of its decisions:  
In D-99-11 (Gaz Metro), the Régie concluded,  
81McShane Pre-filed Evidence, NSPI Rebuttal Evidence, Exhibit N-153, p. 61  
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Following the analysis of the evidence submitted, the Régie is of the opinion  
that only the operating costs should be taken into account in the calculation  
of the working capital. According to the Régie, the global approach  
over-estimates the requirements by considering not only the cash flows  
related to the distribution service but by also taking into account the return  
on equity and retained earnings which advantages the shareholders. A  
lead-lag study, according to the global methodology, would increase  
significantly the cash working capital, without, however, assuring that such a  
result would accurately reflect reality. The Régie considers that it is  
preferable to limit the lead-lag study analysis to only the income statement  
items directly related to the service itself. Moreover, the Régie notes that few  
rulings have been issued on this subject up until now.  
In D-2001-55 (Gazifère), the Régie stated,  
the Régie, in its decision, takes account of the conclusion of Bonbright to the  
effect that any method produces approximate results and that the objective  
is to determine an amount which is reasonable, without a degree of  
refinement that causes the costs to be higher than the associated benefits:  
>None of the methods for calculating the working capital  
allowance will produce a result that is precisely correct. The  
purpose of the calculation should be to arrive at an amount  
that is reasonable and contains no obvious defects, and  
which is not so time-consuming to compute that the cost  
exceeds the benefit.=  
The Régie accepts the distributor=s demonstration that the depreciation  
expense is a valid element of the global method. Depreciation does not  
generate a cash expenditure; however, the recovery of the depreciation  
expense is delayed for the period of the revenue lag. Meanwhile, the  
investors continue to provide the funds for a certain portion of the  
depreciation expense.  
With regard to the inclusion of interest expense and dividends proposed by  
OC/ACEF, the Régie considers that these payments are made from funds  
that belong to the investors and arise from the manner of financing, which is  
taken into account in the capital structure. If one were to consider that the  
delay in the payment of interest and dividends constitutes a source of funds,  
it is also necessary, according to the Régie, to consider all of the other  
elements of the capital structure and thus ultimately to examine whether the  
global method is well-founded.  
The Régie considers that it would not be fair to order Gazifère to use the  
global method. This method introduces, according to the Régie, certain  
complexities that have not been fully studied.  
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The Régie is of opinion that the evidence submitted is insufficient to justify  
such a fundamental change in the methodology used to calculate working  
capital. The current methodology having the advantage of having been  
tested, it is up to the intervenor OC/ACEF to demonstrate, in a convincing  
way, that the current method is no longer appropriate. In the opinion of the  
Régie, this demonstration was not made. The Régie considers that it would  
not be appropriate to adopt the methodology suggested by OC/ACEF.  
(NSPI Rebuttal Evidence, Exhibit N-153, pp.67-69)  
[266] Ms. McShane noted that adoption of the Aglobal@ approach in NSPI=s case would increase  
its CWC requirement, primarily because the equity return is earned by common equity investors  
when the service is provided, but the collection of the return is delayed until payment is received  
from ratepayers (i.e., the net lag on the equity return would be equivalent to the revenue lag resulting  
from the collection of NSPI=s billings, which the Company states is 42 days).  
[267] Ms. McShane testified that the Alberta Energy and Utilities Board has been using the  
Aglobal@ approach in the calculation of CWC allowance since 1988. Adopting NSPI=s figures with  
respect to revenue and expense lags, Ms. McShane estimated that using the Aglobal@ approach  
would increase NSPI=s CWC allowance by as much as $13 million over its present estimate of  
$29.4 million.  
[268] In cross-examination by Mr. Grant, Ms. McShane agreed that in the case of Newfoundland  
and Labrador Hydro, the utility adjusted its interest expense downward to account for the timing of  
payments on bonds.82  
82Transcript, November 22, 2005, pp. 977-979  
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5.3.2 Submissions - Intervenors  
[269] Both Mr. Drazen and James T. Selecky, of Brubaker & Associates, Inc., contend that  
interest expense and the payment of preferred dividends should be taken into account in  
the calculation of CWC allowance. They each noted that the Company collects revenues  
from its customer billings throughout the year, but the payments of interest occur as late as  
semi-annually, in the case of long-term bonds, and quarterly, in the case of preferred  
dividend payments. In both cases, they note that NSPI collects its revenues in advance of  
the time it is required to pay the interest and preferred dividends. Thus, in their view, these  
funds represent a source of working capital which should be taken into account in reducing  
the CWC requirement.83  
[270] Mr. Drazen, when challenged on his methodology in cross-examination by René Gallant,  
Counsel for NSPI, noted that other utilities like Fortis BC and Centra Manitoba include interest  
expense and preferred dividend payments in their calculation of the CWC, to the exclusion of other  
elements such as depreciation and common equity return. He added that Ms. McShane identified  
these two utilities, in her pre-filed evidence, as adopting this methodology. Mr. Drazen also noted  
that in hearings involving Newfoundland and Labrador Hydro, the regulator approved a practice  
which takes into account the recovery of revenues from customers to pay interest, thereby reducing  
the cost of the utility=s debt. While he acknowledged that this methodology is different than what  
83Drazen Pre-filed Evidence, Exhibit N-95, pp. 9-10; Selecky Pre-filed Evidence,  
Exhibit N-91, pp. 4-5  
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he suggests, the final result, he stated, is exactly the same as that calculated using his proposed  
methodology.84  
5.3.3 Findings  
[271] With respect to this issue, NSPI submits that interest expense and the payment of preferred  
dividends should not be taken into account in the calculation of CWC allowance. Alternatively, in  
the event that the Board finds that these expense items should be included, Ms. McShane asserts that  
such a finding would require the Board to adopt the Aglobal@ approach, taking into account  
depreciation expense, as well as return on common equity. To do otherwise, she suggests, amounts  
to Acherry-picking@ the items which will be included in the calculation.  
[272] For Mr. Drazen and Mr. Selecky, the issue simply comes down to the fact that NSPI collects  
its revenue from customers before it is required to pay interest expense and preferred dividend  
payments. In their view, NSPI=s use of these funds in the intervening period effectively reduces its  
CWC requirement.  
[273] In their submissions, Avon and SEB both submit that interest expense and preferred dividend  
payments should be taken into account in the determination of CWC allowance, but not depreciation  
expense or common equity return. Avon highlighted the distinction between these expenses as  
follows:  
84Transcript, December 1, 2005, pp. 3189-3190  
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147.  
It is submitted that the global approach advocated by Ms. McShane does not  
accurately measure the Company=s need for utilization of cash which is the function  
of the allowance for CWC. Depreciation is not a cash obligation of the company.  
For the payment of dividends on common equity there is a discretion on the part of  
the company with respect to the time and amount. Payments of preferred dividends,  
by contrast, are cash payments, the time and amount of which are subject to terms  
agreed to by investors. Similarly, interest payment upon debt is a cash payment  
required in accordance with the terms agreed to between the company and the  
holders of its debt.  
(Avon, Redacted Closing Submission, p. 32)  
[274] While maintaining that the inclusion of interest expense and preferred dividend payments  
should not be considered without adopting the Aglobal@ approach, Ms. McShane acknowledged on  
cross-examination by George T.H. Cooper, Q.C., Counsel for SEB, that there is a distinction  
between these and other expenses included in the Aglobal@ approach, in that depreciation expense is  
not a cash obligation and that the payment of common equity return is subject to the discretion of the  
Company in terms of the timing and amount of dividends paid on common shares. Further, she  
acknowledged that revenue collected by NSPI for payment of interest expense and preferred  
dividend payments do contribute to the cash NSPI has available to it to earn a return.85  
[275] The Board has considered the evidence of Mr. Drazen and Mr. Selecky that interest expense  
and preferred dividends should be taken into account in calculating the CWC. The Board  
understands the reasons why they argue in favour of their inclusion in the CWC calculations.  
However, the Board notes that other regulators have considered this matter, and have disagreed with  
the inclusion of interest and preferred dividends in the calculation of CWC.  
85Transcript, November 22, 2005, pp. 931-935  
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[276] Ms. McShane, in NSPI=s Rebuttal Evidence of November 7, 2005, quoted from a National  
Energy Board decision of August 1986, which dealt with this matter:  
With regard to the payment of interest on long-term debt and preferred share dividends, the  
Board is of the opinion that these items, which are not a function of operations but of the  
financing of the Company, are components of the rate of return. Furthermore, they relate to  
contractual obligations entered into between Westcoast=s shareholders and the Company=s  
other investors. As such, they do not involve the day-to-day operations of the Company, and  
do not properly belong in the calculation of the cash working capital allowance. (National  
Energy Board, Reasons for Decision, Westcoast Transmission Company Limited, August  
1986)  
(Exhibit N-153, p. 70)  
[277] The NEB, in its decision, was dealing with whether interest expenses and preferred dividends  
ought to be included in the calculation of the cash working capital allowance. It states that cash  
working capital allowance is intended to measure the cash requirement for the day-to-day operations  
of the Company. The NEB was of the view that interest on long-term debt and preferred share  
dividends are not a function of the day-to-day operations, and thus do not belong in the calculation  
of cash working capital. Rather, they are a function of the financing of the Company, and thus are  
components of the rate of return. In addition, according to the NEB, these items relate to contractual  
obligations entered into between the Company=s shareholders and other investors.  
[278] Ms. McShane, in Exhibit N-153, also set out the views of the Régie de l=Energie du Québec,  
as contained in two cases concerning the same matter. The views of the Régie can be summed up  
with the following quote:  
With regard to the inclusion of interest expense and dividends proposed by OC/ACEF, the  
Regie considers that these payments are made from funds that belong to the investors and  
arise from the manner of financing, which is taken into account in the capital structure. If one  
were to consider that the delay in the payment of interest and dividends constitutes a source  
of funds, it is also necessary, according to the Régie, to consider all of the other elements of  
the capital structure and thus ultimately to examine whether the global method is well-  
founded.  
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The Régie considers that it would not be fair to order Gazifère to use the global method. This  
method introduces, according to the Régie, certain complexities that have not been fully  
studied.  
(Exhibit N-153, pp. 68-69)  
[279] Ms. McShane makes the case that if the interest on long-term debt and the preferred  
dividends are to be included in the calculation of the CWC, then the calculation must also include  
depreciation expense and return on equity:  
... If the cash working capital allowance is to be interpreted in the broad or Aglobal@ sense of  
measuring the full extent to which investors have financed the revenue requirement, leads  
and lags on all elements of the return of and on capital must be taken into account. Inclusion  
of interest payments alone, to the exclusion of depreciation expense and common equity  
return, amounts to Acherry-picking@, and will understate the cash working capital  
requirement....  
(Exhibit N-153, p. 61)  
[280] According to Ms. McShane, were the CWC calculations to include depreciation and all  
return on capital items, there would be an increase in the CWC of $6.60 million, rather than a  
decrease as proposed by Mr. Drazen and Mr. Selecky.  
[281] Based on the evidence, the Board is not persuaded that the methods advocated by Mr. Drazen  
and Mr. Selecky should be adopted for purposes of calculating CWC in this rate case. The Board  
agrees with the observation of the Régie that A... this method introduces ... certain complexities that  
have not been fully studied.@ For the Board to move in that direction, a more detailed consideration  
of the Aglobal@ approach would be required. Accordingly, the Board accepts the recommendation  
of Ms. McShane concerning this matter.  
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[282] At a future rate hearing, should additional evidence be presented concerning the Aglobal@  
approach and the inclusion of interest expenses and preferred dividends in the calculation of CWC,  
the Board would be willing to reconsider the matter.  
5.4  
Securitization of Accounts Receivable  
5.4.1 Submissions - NSPI  
[283] NSPI maintains that the funds received from its accounts receivable securitization program  
should not be taken into account in determining the Company=s CWC allowance.  
[284] Under this program, NSPI sells a Aco-ownership interest@ in a portion of its accounts  
receivable to a trust. The trust, in turn, pledges its co-ownership interest as security in order to  
obtain funds from investors, which the trust lends to NSPI. NSPI pays securitization fees to the trust  
in an amount equivalent to interest charges on a conventional short-term loan (i.e., $2.4 million for  
the 2006 test year86). The trust pays a portion of the securitization fees back to the investors, who  
are ultimately repaid their original loan by NSPI, through the trust.  
86NSPI Application, Exhibit N-2, Appendix A, Table 10  
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[285] Accounting rules allow the securitization transaction to be treated as a sale of receivables.  
For reporting purposes, the affected accounts receivable are removed from the balance sheet, along  
with the associated short-term debt, which is paid from the proceeds of the accounts receivable  
transferred to the trust.87  
[286] Ms. McShane submits that customers of NSPI benefit in two ways from this arrangement.  
First, by reducing the amount of capital on NSPI=s balance sheet, the Company reduces its liability  
for Large Corporation Tax. This tax saving is reflected in the revenue requirement and passed along  
to NSPI=s customers. Second, the securitization allows NSPI to lower the costs of its short-term  
financing, because the security for the loan is comprised of relatively liquid assets.88 The Board  
infers that the reduced costs of the short-term financing results in lower interest expenses for NSPI.  
[287] In Ms. McShane=s opinion, the securitization is substantively the same as using accounts  
receivable as collateral for a short-term credit facility. In obtaining short-term financing in this  
fashion, she maintains that NSPI has not reduced its revenue lag and, thus, not reduced its CWC  
allowance. In her view, the fundamental difficulty with the intervenors= suggestion that the  
securitization reduces the CWC allowance is described as follows:  
87NSPI, Rebuttal Evidence, Exhibit N-153, p. 79  
88McShane, Pre-filed Evidence, NSPI Rebuttal Evidence, Exhibit N-153, p. 73  
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To claim that the accounts receivable securitization program reduces NSPI=s revenue lag is  
tantamount to claiming that any utility whose short-term credit facilities are secured by  
accounts receivable has reduced its revenue lag. Utilities require short-term debt because  
there is a lag between rendering service and receiving payment. The short-term debt is the  
investor-financing that bridges the gap. It is a circular argument to then claim that because  
the utility has obtained the short-term debt to bridge the gap, the lag between provision of  
service and receipt of revenues has been reduced. To claim that the revenue lag is reduced  
by the securitization program (thus reducing the cash working capital requirement), is  
equivalent to claiming that NSPI does not need the short-term debt, a clearly erroneous  
conclusion.  
(NSPI, Rebuttal Evidence, Exhibit N-153, p. 73)  
[288] During its testimony at the hearing, the Finance Panel reiterated NSPI=s position that the  
funds obtained from the securitization program should not be included in the CWC allowance. Ms.  
Zeda Redden, NSPI=s General Manager, Finance, testified that the program merely replaces the  
debt owed to one group of investors (i.e., short-term debt holders) with new debt owed to the trust.  
Thus, in her view, the transaction does not affect CWC. She added that NSPI still retains all of the  
risk with respect to the collection of the accounts receivable which have been securitized. Further,  
she noted that financial institutions such as banks and rating agencies consider the securitization to  
be outstanding debt, which is taken into account in conducting their credit assessments.89  
5.4.2 Submissions - Intervenors  
89Transcript, November 22, 2005, pp. 936-937; NSPI Rebuttal Evidence, Exhibit N-153, p. 80  
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[289] Both Mr. Drazen and Mr. Selecky are of the view that the securitization program should be  
taken into account in the calculation of NSPI=s CWC requirement. Both witnesses noted in their  
Direct Evidence that NSPI expects to securitize about $53.75 million of accounts receivable per  
month,90 representing approximately 60% of its monthly revenues.91 Further, they note that NSPI=s  
customers are charged the projected annual cost of $2.4 million to implement the securitization  
program. This amount is imputed as interest expense and included in the Company=s revenue  
requirement.  
[290] Mr. Selecky suggests that the monies received from the securitization program effectively  
reduces NSPI=s CWC requirement:  
... the securitization of the receivables provides the Company with cash that reduces its short-  
term debt. Therefore, NSPI has cash available quicker than it otherwise would. The  
availability of this cash reduces the revenue lag days utilized to calculate its cash working  
capital requirement.  
(Selecky Direct Evidence, Exhibit N-91, p. 7)  
[291] Both Mr. Selecky and Mr. Drazen accounted for the impact of the securitization program by  
reducing the revenue lag to be used in the calculation of the CWC. Mr. Selecky estimated that NSPI  
would experience a 10 day lag in receiving the securitized funds, resulting in a weighted revenue lag  
of 22.8 days.92 In the absence of information from NSPI with respect to the timing of receipt of  
monies from the securitization program, Mr. Drazen assumed that the Company received the monies  
immediately upon request, resulting in an average revenue lag of 19.2 days.93 Both Mr. Drazen and  
90SEB IR-213, Attachment 1  
91Drazen Pre-filed Evidence, Exhibit N-95, p. 11; Selecky Pre-filed Evidence, Exhibit N-91, p. 7  
92Selecky Pre-filed Evidence, Exhibit N-91, p. 8  
93Drazen Pre-filed Evidence, Exhibit N-95, p.12  
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Mr. Selecky then incorporated the revised revenue lag into their calculation of the CWC allowance  
(see Appendix C).  
[292] The Board observes that the significant decrease in the revenue lag calculated by both Mr.  
Drazen and Mr. Selecky effectively results in a negative CWC requirement, albeit in varying degrees  
because of the different assumptions made by both witnesses with respect to other expense lead/lag  
items discussed elsewhere. Mr. Drazen indicated that this caused him no concern since it is simply a  
reflection that the Company=s cash flow is such that revenues are collected before the monies have  
to be paid out. He described this as Amoney in the bank@, stating that it is a source of financing for  
the Company. He noted that other utilities have shown a negative CWC in their filings.94  
[293] In cross-examination by Mr. Gallant, Mr. Drazen and Mr. Selecky each acknowledged that  
the securitization of accounts receivable by a company is different than the practice of Afactoring@  
(i.e., the sale of) receivables. They agreed that the latter results in the creation of revenue from the  
sale of a future revenue stream, while securitization results in the creation of debt. They were also  
unable to identify any other jurisdiction where securitization, as opposed to Afactoring@, is approved  
by regulators.95  
94Drazen Pre-filed Evidence, Exhibit N-95, p.13  
95Transcript, December 1, 2005, pp. 3193-3194 (Drazen); Transcript, December 2, 2005,  
pp. 3319-3320 (Selecky)  
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5.4.3 Findings  
[294] The Board has considered the respective submissions relating to the treatment to be afforded  
the securitization of accounts receivable in the determination of CWC allowance. In this regard, the  
Board reviewed the evidence of Ms. McShane, Mr. Drazen and Mr. Selecky, along with the  
submissions of the parties.  
[295] The Board accepts the evidence of Ms. McShane that the securitization transaction is  
substantively similar in nature to a utility that pledges its accounts receivable as collateral to obtain a  
short-term credit facility. In effect, the transaction simply substitutes the debt owed by NSPI to one  
group (i.e., short-term bond holders) by debt owed to another group (i.e., the trust). Securitization is  
distinct from a sale or Afactoring@ of receivables because, under the securitization program, NSPI  
continues to bear the risk of ultimately collecting the accounts receivable and the short-term debt  
must be repaid. No debt is issued under >factoring@, which instead produces revenue from the sale  
of a future revenue stream. The Board concludes that the securitization program does not reduce  
NSPI=s revenue lag and, accordingly, the transactions should have no impact on the CWC  
allowance requirement.  
[296] The Board notes that the transactions benefit NSPI=s customers through reduced Large  
Corporation Tax and also, the Board infers, through lower financing charges96.  
96NSPI reports the securitization fees as deductions to Other Revenues (Exhibit N-2, Appendix A,  
Table 1  
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5.5  
Other Lead/Lag Assumptions  
5.5.1 Submissions - NSPI  
[297] NSPI states in its application that this marks the first opportunity in some time for the  
Company to carry out a lead/lag study, noting that the amount of CWC was not relevant to the  
setting of rates based on the capitalization methodology previously applied by the Board. NSPI  
submits that it has undertaken a rigorous approach to the determination of CWC in this rate  
application.97  
[298] The Company asserts that its lead/lag assumptions are reasonable, submitting that a CWC  
allowance of $29.4 million should be included in the rate base.  
[299] Following the conclusion of the hearing, NSPI raised a further issue with respect to the  
calculation of the rate base, asserting that during the course of the hearing it became apparent, in  
NSPI=s view, that the 2006 rate base is understated by $30.0 million due to the exclusion of the  
2005 Q1 tax deferral and the potential increase of the long-term receivable associated with the gas  
contract achieved as a result of the November 16, 2005 settlement. It submits that if the rate base is  
to be adjusted as requested by the intervenors, then adjustments to the 2005 Q1 tax deferral and the  
97NSPI Rebuttal Evidence, Exhibit N-153, p. 83  
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long-term receivable must also be taken into account, increasing the revenue requirement by  
approximately $2.0 million.98  
5.5.2 Submissions - Intervenors  
[300] In evidence filed on behalf of Avon, Mr. Drazen challenges some of the lead/lag assumptions  
made by NSPI in the determination of its CWC requirement. A table showing a summary of Mr.  
Drazen=s conclusions respecting lead/lag assumptions, along with those of NSPI and Mr. Selecky, is  
contained in Appendix C to this decision. His determination of NSPI=s CWC requirement for the  
2006 test year is negative $54.8 million. Using the same methodology to calculate the 2005 CWC  
requirement, he averaged the two figures at negative $51.1 million, compared to NSPI=s claimed  
average of positive $29.4 million.  
98NSPI Redacted Closing Argument, p. 71 and p. 77  
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[301] In addition to Mr. Drazen=s inclusion of the HST, the securitization of accounts receivable,  
as well as interest and preferred dividends in the calculation of the CWC, which have already been  
discussed, part of the difference is accounted for by differing lead/lag assumptions. In his Direct  
Evidence, Mr. Drazen indicated that NSPI shows a longer revenue lag and shorter expense lags than  
it did in the 2005 rate case. He notes that these two factors combine to increase the net lag in  
recovery, resulting in a larger CWC requirement.99 NSPI=s lag assumptions for the 2005 and 2006  
rate case, along with the estimates of Mr. Drazen and Mr. Selecky for the 2006 test year, are  
contained in the following Table which was compiled by the Board100:  
PROPOSED REVENUE AND EXPENSE LAGS  
2005  
Rate Case  
2006  
Rate Case  
Drazen  
2006  
Selecky  
2006  
Revenue - monthly  
- bi-monthly  
Weighted Average  
31.0 days  
53.0  
42.0  
36.0 days  
53.0  
42.0  
-
-
-
-
38.9 days  
42.0  
Labour  
Non-labour operating  
Fuel & purchased power 29.4  
Grants in lieu of taxes  
Income taxes  
21.0  
50.0  
15.0  
45.0  
30.4  
(91.0)  
30.0  
21.0  
50.0  
29.5  
(91.0)  
53.0  
15.0  
45.0  
30.0  
(91.0)  
30.0  
**  
**  
** Not included in study  
99Drazen Pre-filed Evidence, Exhibit N-95, pp. 7-8  
100Drazen Pre-filed Evidence, Exhibit N-95, p. 7 and p. 13  
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[302] Backing out the impact of the securitization program, which the Board has concluded should  
not be taken into account in determinating the CWC allowance, Mr. Drazen=s projected revenue lag  
should be adjusted to 38.9 days, rather than the 19.2 days contained in his Direct Evidence. In  
support of this conclusion respecting 38.9 days, Mr. Drazen noted that NSPI revised its 50/50 split  
of monthly and bi-monthly billings (which produces an average lag of 42 days) to a 64/36101 split  
(which produces a weighted average of 38.9 days).102  
[303] Further, in Mr. Drazen=s opinion, NSPI has not explained the reasons for reducing most of  
the expense lags from those suggested by NSPI in the 2005 rate case, noting that the expense lag  
relating to fuel and purchased power is the only expense lag which has increased, albeit by a  
marginal amount. He recommends that the expense lags remain at the 2005 levels.  
101NSPI Application, Exhibit N-2, Appendix A, Table 17, lines 15-26  
102Drazen Pre-filed Evidence, Exhibit N-95, p. 11  
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[304] With respect to NSPI=s inclusion of income taxes and grants in lieu of taxes in the CWC  
calculation, Mr. Drazen stated that this is consistent with his recommendation during the last Rate  
hearing. He also noted that the average expense lag of negative 91 days for grants in lieu of taxes is  
virtually identical to the number recommended by him in last year=s rate case. However, with  
respect to income taxes, Mr. Drazen asserts that the average lag should be 53 days rather than the 30  
days estimated by NSPI. In support of this submission, Mr. Drazen refers to Avon IR-48(f),  
Attachment 1, in the 2005 rate case, which outlined that 83% of income taxes are paid monthly, with  
the balance of 17% being paid the following February. While he acknowledges that the ultimate  
amount paid depends on the Company=s performance, he states that an iterative process is required  
to determine the actual amount to be paid for income taxes.103  
[305] Mr. Drazen also suggests that other sources of working capital may include a reserve for bad  
debts and the amortization of deferred financing charges (defeasance costs). However, he indicated  
that NSPI had not provided sufficient information to assess these two other potential sources of  
working capital.104  
[306] In support of his assertion that NSPI=s stated rate base is overstated, Mr. Drazen compiled an  
analysis of NSPI=s rate base, comparing the amounts shown in the 2005 and 2006 rate applications.  
103Drazen Pre-filed Evidence, Exhibit N-95, p. 8  
104Drazen Pre-filed Evidence, Exhibit N-95, p. 14  
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[307] With respect to the revenue lag, Mr. Selecky adopted the 42 day lag estimated by NSPI and  
deducted therefrom a number of days to account for the securitization program, resulting in a  
weighted revenue lag of 22.8 days. Given the Board=s exclusion of the securitization program from  
the determination of CWC, the Board observes that Mr. Selecky agreed, at least implicitly, with  
NSPI=s 42 day revenue lag.  
5.5.3 Findings  
[308] The 2006 test year marks the first time that the determination of CWC allowance is relevant  
to the setting of rates. Prior to this point, CWC was not a factor in establishing rates under the  
capitalization methodology. However, it is a component of the rate base approach to be followed in  
this application.  
[309] The Board is mindful of Mr. Drazen=s observation that, compared to other rate base items,  
CWC is one of the most difficult to determine because it is not tied to a specific expenditure.105 As  
noted by Mr. Blunden in his testimony, the determination of CWC is merely intended to serve as a  
proxy for actual working capital, which fluctuates throughout the year. He stated that, with the  
exception of CWC, all other items in the rate base can be traced back to the Company=s external  
audited financial statements.106 Against this backdrop, the Board considers it important that this  
topic be broached with some caution.  
[310] Four issues arise from the evidence and the submissions with respect to the lead/lag  
assumptions for the determination of the CWC allowance: 1) the determination of the appropriate  
105Drazen Pre-filed Evidence, Exhibit N-95, p. 5  
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revenue lag (42 days versus 38.9 days); 2) the appropriate expense lag for income taxes (30 days  
versus 53 days); 3) whether the other expense lags should be set at the levels estimated by NSPI  
during the 2005 rate case107 or at the new estimated levels; and 4) whether other potential sources of  
CWC should be considered.  
[311] Removing the impact of the securitization program upon the revenue lag, Mr. Drazen  
calculated 38.9 days for the revenue lag, compared to the 42 days adopted by NSPI and, without  
discussion of the point, by Mr. Selecky. Mr. Drazen used information provided by NSPI to calculate  
a weighted average of 38.9 days. He noted that the Company confirmed, during last year=s rate  
hearing, that the correct split between monthly and bi-monthly billings was 50/50, yielding an  
average lag of 42 days. However, in the present rate application, NSPI revised the monthly/bi-  
monthly split to 64/36,108 but maintained the 42 day lag. Mr. Drazen indicated that this revised split  
reduces the weighted average from 42 days to 38.9 days.  
[312] NSPI provided no evidence to explain why revising its split of monthly and bi-monthly  
billings from 50/50 to 64/36 would not alter the weighted average of 42 days, nor did it cross-  
106Transcript, November 22, 2005, pp. 946-947  
107Undertaking U-34 (2005 Rate application SEB IR-222)  
108NSPI Application, Exhibit N-2, Table 17, lines 15-26  
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examine Mr. Drazen on his calculation. Accordingly, the Board accepts Mr. Drazen=s calculation  
of the revenue lag as being 38.9 days.  
[313] Similarly, Mr. Drazen referred to Avon IR-48(f), Attachment 1, in the 2005 rate case, in  
determining that the average lag for income taxes should be 53 days rather than the 30 days  
estimated by NSPI. That IR response noted that 83% of income taxes are paid monthly, with the  
balance of 17% being paid the following February. He acknowledged that the ultimate amount paid  
for income taxes depends on the Company=s performance and more information would be required  
to determine the actual timing for the payment of income taxes. NSPI did not provide any evidence  
during this application to revise its answer to last year=s response to Avon IR-48(f) (even though  
Mr. Drazen made specific reference to it in his pre-filed evidence), nor did counsel for NSPI cross-  
examine Mr. Drazen on the point. In the absence of further evidence on this issue, the Board accepts  
Mr. Drazen=s evidence that the expense lag with respect to income taxes should be 53 days rather  
than 30 days.  
[314] In the present application, NSPI has reduced the expense lags for labour, non-labour and fuel  
from those it provided during the 2005 rate case. Mr. Drazen indicates that the expense lags should  
remain as described by NSPI during the 2005 rate case until further information is provided. He  
states that the decreases in these expense lags were not explained by NSPI. The Board concurs with  
Mr. Drazen.  
[315] Based on the above findings, the CWC requirement would be $12.25 million (averaged with  
2005 F). The Board=s conclusions with respect to the determination of NSPI=s CWC allowance are  
summarized in the following Table:  
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SUMMARY OF BOARD FINDINGS  
2006 Cash Working Capital Requirement  
(Dollars in Millions)  
Category  
Lag  
Days  
(a)  
Net  
% of  
Year (c)  
[(b)/365]  
Annual  
Cost  
(d)  
CWC  
[(c) x (d)]  
Lag Days (b)  
[38.9 days - (a)]  
Revenue lag  
38.9  
Labour  
21  
50  
29.4  
(91)  
53  
17.9  
(11.1)  
9.5  
129.9  
(14.1)  
4.90%  
(3.04)  
2.60  
35.59  
(3.86)  
$119.3  
5.85  
(2.75)  
12.45  
11.60  
(3.26)  
(4.4)  
Non-labour operating  
Fuel & purchased power  
Grants in lieu of taxes  
Income taxes  
HST  
90.5  
479.0*  
32.6  
84.4  
Total  
19.49  
Less customer deposits  
CWC requirement- 2006  
(7.0)  
$12.5  
Note: 2005 CWC was calculated at $12.0; Average is $12.25  
*$479.0 million is the fuel budget in original filing  
[316] The Board notes the comments of Mr. Drazen that there may be other potential sources of  
CWC such as a reserve for bad debts and the amortization of deferred financing charges (defeasance  
costs). The Board reiterates that this rate case provided the first occasion to conduct a meaningful  
review of the Company=s CWC requirement. The Board is not prepared to make any further  
adjustment based on other potential sources of CWC at this time, but will continue to monitor this  
issue in subsequent rate hearings.  
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5.6  
Total Rate Base  
[317] NSPI has requested that its Average Regulated Rate Base for 2006 be set at $2.840 billion.  
Of that amount, $29.4 million is the CWC allowance. The Board has reduced the CWC allowance to  
$12.25 million which has the effect of reducing the rate base.  
[318] The only other adjustment to rate base which appears to be justified on the evidence is to  
account for the increase in the long-term receivable resulting from the settlement between NSPI and  
its natural gas supplier. The settlement was reached after the application was filed and provides  
significant benefits to customers in the form of reduced fuel costs. The Board therefore approves an  
increase in the average rate base of $14.45 million to reflect the difference between the long-term  
receivable estimated in the original rate filing and the amount shown in U-76, which takes the  
settlement into account. To the extent that the Board=s decision to increase the estimated natural  
gas resale benefit for the test year has the effect of further increasing the long-term receivable, then  
the Board will allow recovery of a return to reflect that increase. NSPI should include the amount of  
such increase , if any, in its Compliance Filing.  
[319] NSPI also requested that the Board include an amount in rate base for the 2005 Q1 tax  
deferral. However, the amount of the tax deferral has not been finally determined as yet and, in the  
Board=s view, it would be premature to include any amount in rate base at this time. Carrying  
charges on the deferred taxes can be dealt with after the amount is determined and the Company  
applies to the Board for their recovery.  
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6.0  
6.1  
OPERATING, MAINTENANCE AND GENERAL EXPENSES (OM&G)  
Overview  
[320] NSPI projects a $27.8 million increase in Operating, Maintenance and General (OM&G)  
costs for the 2006 test year compared to the 2005 Compliance Filing. The proposed increases for  
each of the four operating groups are set out in the following Table compiled by the Board, based on  
information set out in NSPI's application109:  
OM&G COSTS - Proposed increases  
(Dollars in Millions)  
2005C  
$66.0 M  
65.3 M  
2005F  
$70.4 M  
67.6 M  
36.8 M  
5.6 M  
2006  
$75.3 M  
77.0 M  
44.4 M  
13.1 M  
$209.8 M  
Power Production  
Customer Operations  
Corporate Support  
Corporate Adjustments  
Total OM&G  
37.1 M  
13.6 M  
$182.0 M  
$180.4 M  
[321] In its application, NSPI states that the proposed increases reflect greater costs associated with  
its enhanced storm response and storm proofing of its transmission and distribution system, extra  
spending on power production, maintenance and operations, wage increases, higher pension  
109Exhibit N-1, pp. 70-105 and Exhibit N-2, Appendix B, p. 1  
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expense, higher regulatory costs and increased investment in demand side management. These  
issues are discussed below.  
6.2  
Power Production  
6.2.1 Submissions - NSPI  
[322] Power Production includes expenditures associated with the operation and maintenance of  
NSPI=s generation facilities, as well as general costs for fuel procurement and management. For the  
test year 2006, NSPI proposes to increase these costs by $9.25 million over the 2005 Compliance  
Filing. The primary components of this proposed increase include $4.0 million for increased labour  
costs associated with the new union agreement and non-union labour increases, $1.8 million to  
implement new succession planning and apprentice programs, $3.2 million associated with  
maintenance and scheduled outages, $1.0 million associated with fuel procurement and management,  
and net savings of $0.8 million achieved from other related accounts.  
[323] With respect to the maintenance of the Company=s machinery and equipment associated  
with its generation fleet, NSPI states that it requires an additional $3.2 million comprised of  
maintenance and plant outage costs required to maintain and improve the reliability and availability  
of the generation assets. It notes that increased investment in maintenance is essential as the age and  
expected output of the generation facilities increase. NSPI further notes that OM&G costs will  
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increase in the short to medium term until some point in the future when further capital must be  
invested in generation facilities, followed by a corresponding decrease in OM&G spending.110  
110Exhibit N-1, p. 80 and 84  
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[324] In support of its projected $1.8 million increase for succession planning and apprenticeship  
programs, NSPI cites a demographic study indicating that the Company risks losing almost 50% of  
its trade workforce to retirement in the next five years. Accordingly, it proposes to implement  
succession planning to actively assess the Company=s ability to sustain and replenish its critical  
organizational roles over time. It also proposes to develop apprenticeship programs to allow the  
transfer of skills and knowledge to NSPI=s employee base, resulting, it asserts, in a stable workforce  
in future years.111  
[325] During his testimony, Rick Janega, NSPI=s General Manager, Power Production, stated that  
the costs of approximately 6 to 8 apprentice positions are currently reflected in rates. These  
apprentices are involved in multi-year training programs so they enter NSPI=s workforce over a  
number of years. He testified that the proposed spending increase represents an increment of an  
additional nine auxiliary power engineers at a total annual cost of $750,000.112 The remaining $1.05  
million cost of the succession planning program relates to training and professional development of  
111Exhibit N-1, p. 83  
112Transcript, November 28, 2005, pp. 2282-2283; see also PWC IR-12  
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about 25 supervisors and managers at thermal generating stations and seven engineering staff in  
Generation Services.113  
113PWC IR-12  
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[326] As noted above in this decision, NSPI continues its efforts to improve its fuel procurement  
and management activities within the Company. The $1.0 million increase associated with this  
effort includes increased labour expenses associated with developing the fuel team and hiring a  
senior coal expert, contracting services used to supplement fuel procurement and management, as  
well as consulting services relating to procurement strategy and fuel forecasting.114  
6.2.2 Submissions - Intervenors  
[327] In their submissions, none of the intervenors specifically addressed the proposed $9.25  
million increase in Power Production costs. Further, the proposed increases under this category  
were not seriously challenged during cross-examination of NSPI witnesses.  
6.2.3 Findings  
[328] The Board has considered the evidence concerning the proposed increase for Power  
Production costs in the amount of $9.25 million. As noted above, this evidence was not seriously  
challenged during cross-examination of NSPI=s witnesses, nor was it the specific topic of comment  
during submissions following the hearing.  
114Exhibit N-1, p. 85  
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[329] The largest component of the proposed increase in Power Production costs is directly  
attributable to increased labour costs resulting from a new contract between NSPI and its union  
representing 1,146 unionized employees, which was signed on December 2, 2004 and effective from  
April 1, 2003 until July 31, 2007. There is also a wage increase of 4.0% for all non-union labour.  
Similar union and non-union labour increases have been proposed across all OM&G operating  
groups, including Power Production, Customer Operations and Corporate Support. While projected  
labour increases respecting prior years were reflected in Corporate Adjustments, there has been a  
corresponding downward adjustment in the Corporate Adjustments account for the 2006 test year to  
account for the assignment of labour increases to the other OM&G categories.115 The Board  
approves the labour increases proposed for Power Production in the amount of $4.0 million.  
[330] Further, in the face of a demographic study which suggests that NSPI risks losing 50% of its  
trade workforce to retirement in the next five years, the Board determines that it is prudent, but not  
to the degree proposed by the Company, for NSPI to expand its succession planning and  
apprenticeship programs to ensure that valuable skills and knowledge can be transferred to a stable  
employee base and that the Company is able to sustain important organizational capacity into the  
future. The Board notes that the proposed increase to be included in the test year represents a  
marked increase in spending for this activity. In the view of the Board, an additional amount of $1.0  
million per year (rather than $1.8 million) should adequately address such issues for the 2006 test  
year. NSPI=s Compliance Filing shall reflect this reduction of $800,000.  
115NSPI Application, Exhibit N-1, p.103  
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[331] The Board also approves the proposed $3.2 million increase destined for maintenance and  
scheduled plant outage costs. While customers of NSPI benefit from these expenditures as NSPI  
maintains and improves the reliability and availability of its generation fleet, the customers also  
benefit from another result of these expenditures - NSPI is able to forego, in the short to medium  
term, significant capital investment in new generation facilities.  
[332] Finally, the Board approves NSPI=s proposed costs of $1.0 million associated with the  
implementation of its fuel procurement and management practices to comply with previous  
directions of the Board on this topic. In prior rate decisions, the Board has directed that NSPI make  
fundamental changes in its fuel procurement function. As discussed, NSPI=s activities continue in  
furtherance of these directions. The $1.0 million cost increase approved by the Board will help  
ensure that NSPI achieves the lowest possible fuel costs, to the ultimate benefit of its customers.  
6.3  
Customer Operations  
6.3.1 Submissions - NSPI  
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[333] Customer Operations includes expenditures associated with Regional Operations  
(transmission and distribution systems), Transmission and Distribution Assets (fleet, vegetation  
management), the Ragged Lake control centre, and Customer Service Administration (call centre  
and billing). For the test year 2006, NSPI proposes to increase these costs by $11.7 million over the  
2005 Compliance Filing. The primary components of this proposed increase include $4.0 million  
with respect to enhanced storm response procedures, $5.2 million for increased vegetation  
management, $3.5 million for increased labour costs, $1.3 million for improvements in customer  
service and to the call centre, and net savings of $2.3 million achieved from other related accounts.  
[334] NSPI=s proposed cost increase for enhanced storm response represents an increase from $1.4  
million presently included in rates to $5.4 million allocated for storm response in the 2006 test year.  
The Company notes that its approach to storm response has significantly changed since events like  
Hurricane Juan and the November 2004 snow storm. As a result, NSPI has implemented the  
Emergency Services Restoration Plan (AESRP@), which incorporates many of the recommendations  
suggested by the Board=s consultant, John Sherrod. In its application, NSPI described its increased  
activities related to storm response:  
The key elements of the ESRP include a centralized and integrated decision-making team,  
more and earlier advance preparation, and a more timely deployment of resources in  
response to a major outage event. When NSPI determines that approaching, severe weather  
is likely to result in significant customer outages, it responds with the plan=s methodical,  
advance preparation phase. This includes movement of NSPI and in-province contract  
resources. NSPI power line crews and field operation support staff are put on stand-by in  
staging areas around the province, based on where the Company believes they will be best  
positioned for rapid deployment during and immediately following the storm. Call Centre and  
head office support staff are placed in hotels connected to the NSPI Call Centre in downtown  
Halifax.  
Advance mobilization also includes contract power line and tree crews from within the  
province being placed in accommodations near areas that could be affected by outages. This  
advance deployment results in increased labor, meal, accommodation and fuel costs, which  
are incurred even if the storm does not result in customer outages.  
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The ESRP provides the basis for the Company=s response to anticipated significant outage  
events. Based on experience implementing the plan, NSPI has more effectively responded to  
significant outages. The experience gained through 2004 and 2005 indicate that the  
additional resources required to better track and prepare for severe storms, staff the call  
centre in advance of severe weather, and restore power more quickly to customers results in  
an incremental cost of $4 million annually.  
(Exhibit N-1, p. 89)  
[335] In support of its request that a total of $5.4 million be included for storm response in the  
revenue requirement, NSPI indicates that it has averaged $5.3 million in storm response costs since  
2002.116 Further, NSPI indicates that it spent $5.8 million in 2004 in responding to storms117, and it  
expects 2005 storm response costs to exceed the Company=s original forecast of $5.0 million Aby a  
wide margin@118.  
[336] In its Reply to Closing Argument, NSPI emphasizes that it is not appropriate to compare its  
present request for $5.4 million for 2006 with the $5.8 million figure expended in 2004, the year  
which saw significant weather events like White Juan and the November 2004 snow storm. It notes  
that the ESRP was not in effect until the end of that year. Thus, it asserts, the cost of increased  
storm response activities is not fully reflected in 2004 spending levels. In response to Consumer  
Advocate IR-36, the Company states:  
The Emergency Services Restoration Plan (ESRP) represents a material change in the  
nature of NSPI=s storm response. Since the adoption of the ESRP (during 2004),  
significantly increased resources are now engaged earlier by NSPI in order to prepare for  
impending storms. When bad weather is forecast, NSPI makes a decision to deploy. The  
116Undertaking U-6  
117NSPI Application, Exhibit N-1, p. 90  
118NSPI Redacted Reply to Closing Argument, p. 13  
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weather may or may not materialize or may not cause the amount of damage predicted.  
NSPI will bear the costs regardless. This includes activation of out-of-province line worker  
crews, overnight lodging for call centre personnel, re-deployment of NSPI line worker crews  
within the province and advance logistics activation. In this mode of operation, whether or not  
these resources are ultimately required, costs are incurred.  
(Consumer Advocate IR-36)  
[337] In their testimony, witnesses for NSPI explained that the ESRP sets out an appropriate  
response level depending on the projected severity of an impending storm. For planning purposes,  
storms are categorized according to anticipated severity with Level 1 storms being at the low end of  
the scale and Level 4 storms being the most serious. The ESRP assigns anticipated costs to the  
various storm levels, with the preparation for, and response to, Level 3 storms being the most costly.  
The preparation for a Level 3 storm is projected to cost $375,000, while an actual response to a  
Level 3 storm, if required in the end, is budgeted at $1,850,000. NSPI projects that storm response  
costs could range from a minimum of $3,725,000 to a maximum of $7,800,000, the difference being  
mainly attributable to the estimated occurrence of one Level 3 storm (on the low side) versus three  
Level 3 storms (on the high side).119 For the 2006 test year, it projects $5.4 million for storm  
response. NSPI notes that, under the ESRP, no projected costs are assigned to Level 4 storms like  
White Juan and the November 2004 snow storm, which occur relatively rarely.  
119Undertaking U-6  
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[338] In its application, NSPI also proposes to increase its spending on vegetation management  
from $5.2 million, currently reflected in rates, to $10.4 million for the 2006 test year. It asserts that  
the increased spending will focus on improving reliability on both the transmission and distribution  
systems, with $7.2 million forecasted to be spent on the distribution system, and the remaining $3.2  
million allocated for spending on the transmission system.120 The proposed additional spending on  
the transmission system will, according to NSPI, allow for the treatment of an additional 700  
hectares of the transmission corridor with a combination of mowing and herbicide applications,  
while the proposed investment on the distribution system will be directed towards increased reactive  
and proactive vegetation management. NSPI estimates that approximately 70% of the total spending  
on the distribution system will be allocated to rural feeders.121 The Company states that its spending  
on vegetation management for the distribution system will be prioritized based on a Dollar per  
Avoided Customer Interruption basis.  
120Undertaking U-9  
121Undertaking U-9  
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[339] Improved customer service and communications are the basis on which NSPI seeks an  
additional investment of $1.3 million in 2006 rates. This figure is comprised of $500,000 in  
telephony technology improvements (including enhancements to and testing of the high volume call  
answer (AHVCA@) and interactive voice response (AIVR@) telephone systems), $300,000 for  
increasing quality assurance in the customer service area (e.g., process documentation, complaint  
investigations, and training programs to target specific areas identified through quality monitoring),  
and $500,000 for improved outage communication processes. This latter figure of $500,000  
includes $150,000 on additional customer research to ensure outage processes are better matched to  
customer expectations and $350,000 on additional proactive communications to be conducted  
annually to assist customers with storm preparedness for major weather events and to manage  
customer expectations regarding communication and restoration of power.122  
6.3.2 Submissions - Intervenors and PWC  
[340] A number of the intervenors opposed the proposed spending increase for vegetation  
management, noting that the proposal for 2006 effectively doubles the current budget for this  
activity. Many who opposed this increased expenditure submitted that NSPI had not shown the  
Board why this significant increase was justified. In its Closing Submission, the Consumer  
Advocate submitted:  
50.  
One of the basic requirements to be met by NSPI in applying for an increase in rates  
is to show that each of the proposed expenditures is required and is the most economical or  
lowest expenditure that is needed. That requirement is particularly important when, as at  
present, significant rate increases are being sought at a time when both NSPI and its  
ratepayers are under financial pressure.  
122NSPI Application, Exhibit N-1, p. 91  
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51.  
NSPI witnesses should expect that they will be required to justify proposed expense  
increases. That requirement is not satisfied merely by making the request for rate recovery of  
additional expenses. NSPI must demonstrate to the Board that it has conducted an internal  
evaluation and prioritization of its needs and that the requested expenses truly are necessary.  
(CA, Redacted Closing Submission, para. 50-51)  
[341] In terms of the request for increased spending on vegetation management, the Consumer  
Advocate submitted that NSPI=s justification for this increase is not demonstrated. The Consumer  
Advocate asserted that the Company provided very little information in its responses to Information  
Requests about the need for the requested level of increased spending on this activity and the  
benefits arising therefrom. In response to Consumer Advocate IR-37, NSPI responded to the request  
for information on its vegetation management spending as follows:  
NSPI=s vegetation management expenditures are aimed at reducing vegetation conditions  
which are creating reliability problems (reactive) and those which have the potential to create  
reliability problems (proactive).  
These expenditures are not different from past practices, rather it is for performing greater  
amounts of vegetation management, consistent with past practices to improve reliability.  
Expenditures would be prioritized to provide the best return on the investment. This  
prioritization takes into account safety concerns, the number of customers involved and the  
nature and extent of the reliability impact.  
...  
NSPI is projecting this level of increased spending over the foreseeable future. No final  
decisions or commitments have been taken or made with respect to the projected additional  
expenditures. This work is dependent on monies being approved.@ [Emphasis added]  
(Consumer Advocate IR-37)  
[342] The increase in vegetation management spending is also opposed by Avon, noting that the  
proposed total spending of $10.4 million on this activity is further suspect in light of the fact that  
NSPI has recently consolidated its vegetation management activities with one third party contractor,  
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achieving 20% savings on its costs. Thus, factoring in this savings, the projected budget for the  
2006 test year would, in effect, be 20% over the proposed $10.4 million amount.123  
123Transcript, November 14, 2005, pp. 195-196  
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[343] Avon also notes that during the Board=s Power Outage Review earlier in 2005, NSPI  
indicated that tree trimming and widening of easements were the most cost effective means of  
improving the reliability of the system, estimating that these activities would cost an additional $5  
million.124 Despite this estimate, Avon highlighted that the additional $5.2 million now requested by  
NSPI only relates to tree trimming within existing easements rather than a widening of easements as  
proposed during the Power Outage Review.125 Avon added that in NSPI=s 69 KV Right-of-Way  
Widening Assessment filed with the Board in November 2005 pursuant to the Power Outage  
Review, NSPI described in detail its widening activities by corridor and kilometer, and estimated a  
budget of $500,000 for 2006 with respect to this work.126 In contrast, Avon noted that no such plan  
was submitted during this rate hearing with respect to the proposed expenditures associated with  
vegetation management.  
[344] Other intervenors also expressed concern about the extent of the increase sought by NSPI  
with respect to vegetation management. In its Closing Submission, the CME submits that the  
proposed increase Ais too rich for what is required at the present time and it certainly is not timely  
with respect to the magnitude of the potential rate increased [sic] facing all Nova Scotians.@127 It  
124Transcript, November 14, 2005, pp. 189-191  
125Avon, Redacted Closing Submission, p. 43  
126Undertaking U-7  
127CME, Redacted Closing Submission, p. 13  
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urges the Board to ensure that any increased expenditures that it approves are indeed necessary and  
that the expenses are Amatched@ to the work that is actually required.  
[345] HRM notes that the $10.4 million budget proposed for the 2006 test year is more than double  
the figure which was identified in the Capital Project Authorization filed by NSPI in 1999 and  
approved by the Board in 2001. It questions whether NSPI=s request for this increase in vegetation  
management is driven by the Company=s reduction of Power Line Technicians.128  
[346] The Province, however, is supportive of NSPI=s request for additional spending of $5.2  
million on vegetation management. It states that these costs are to be incurred in response to  
concerns raised during the Power Outage Review following the November 2004 storm, noting  
NSPI=s response to Consumer Advocate IR-37, in which the Company expected the additional  
expenditures for vegetation management to result in a 25% improvement in tree related customer  
interruptions and a 30% improvement in related customer hours of operation. Nevertheless, the  
Province asked the Board to maintain a Awatchful eye@ to ensure that these expenditures translate  
into improved reliability.129  
[347] Similarly, SEB submits that the Board should carefully examine NSPI=s reasons for this  
increased spending before approving the Company=s request.  
128HRM, Redacted Closing Submission, p. 17  
129Province, Redacted Closing Submission, p. 25  
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[348] In its Report, PWC notes the Company=s assertion that the proposed vegetation management  
expenses will help contain, but not reduce, spending in OM&G. While NSPI provided an estimate  
of improved reliability factors resulting from the additional investment in vegetation management,  
PWC claims that the Company did not provide an estimate of the savings to be achieved with respect  
to reduced outage and repair costs in future years. Given that lack of information, PWC is unable to  
conclude whether the additional $5.2 million is reasonable.130  
[349] With respect to NSPI=s request for an additional $1.3 million investment for improved  
customer service relating to telephony technology improvements, improved outage communication  
processes and increased quality assurance, the Province expressed concerns respecting the frequency  
of the expenses being sought by NSPI. In particular, it questioned whether a $250,000 stress test of  
the Company=s telephony systems and monies for research on outage communications are necessary  
on an annual basis, given that NSPI=s request, if approved, would effectively include these charges  
in rates. While acknowledging that this may not be an issue in 2006, the Province submitted that it  
should be considered in greater detail in future rate hearings.131 PWC also concluded in its Report  
that certain of the expenses related to telephony technology appear to be one-time costs and  
recommended that they be included in the revenue requirement over several years.132  
130PWC, Pre-filed Evidence, Exhibit N-84, p. 21  
131Province, Redacted Closing Submission, pp. 25-26  
132PWC, Pre-filed Evidence, Exhibit N-84, p. 23  
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6.3.3 Findings  
[350] For the 2006 test year, NSPI requests an additional $11.7 million in spending for Customer  
Operations.  
[351] The Board approves the labour increases for Customer Operations in the amount of $3.5  
million resulting from the new labour agreement discussed above.  
[352] NSPI proposed an additional increase of $500,000 respecting succession planning for power  
line technicians. For the reasons described above respecting Power Production succession planning,  
the Board reduces the proposed spending increase from $500,000 to $300,000.  
[353] With respect to the costs related to enhanced storm response, none of the intervenors  
seriously questioned the necessity for increased spending in this area. NSPI=s request would  
increase projected expenditures in this category from the current level of $1.4 million per year to a  
total of $5.4 million in 2006 rates.  
[354] The Board is mindful that NSPI has greatly enhanced its storm response activities since  
major storm events like Hurricane Juan and the November 2004 storm.  
[355] As witnesses for NSPI described in their testimony at the hearing, the Company implemented  
its ESRP by late 2004, providing for advance preparation and more timely deployment of resources  
in response to a major power outage event. As noted in its evidence, not all forecasted weather  
events ultimately occur as projected. However, under the ESRP, advance preparation and  
mobilization are required in all instances.  
[356] The Board is satisfied that NSPI=s storm preparedness and response under the ESRP  
represents a marked improvement in service by the Company over that which is currently reflected  
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in rates. Further, the Board is satisfied that the $5.4 million is representative of the current level of  
expenditures being incurred by NSPI on an annual basis for these activities. While present rates  
provide for annual spending of $1.4 million with respect to storm response, NSPI has averaged $5.3  
million per year in storm response costs since 2002133. Based on the implementation of its ESRP,  
with its consequent impact on the degree of preparation which hinges on the predicted severity of  
upcoming storms, the Board finds that the proposed annual cost of $5.4 million for NSPI=s storm  
response is reasonable and appropriate. Moreover, based upon the Board=s findings in its Power  
Outage Review, it is clear that NSPI=s customers desire NSPI to provide these enhanced storm  
response activities. The Board commends NSPI for its efforts in implementing the ESRP and it  
approves the additional $4.0 million directed to this initiative.  
[357] While the issue of vegetation management also arose in the context of the Power Outage  
Review, there was a difference of opinion among the parties at the hearing with respect to the  
necessity for increased spending for such activities. NSPI asserts that increasing expenditures on  
vegetation management to $10.4 million will improve reliability on both the transmission and  
distribution systems, but some of the intervenors note that this proposed increase will double the  
level of vegetation management currently reflected in rates.  
133Undertaking U-6  
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[358] Having reviewed the evidence, it appears that the primary concern of the intervenors relates  
to NSPI=s failure to fully justify the extent of the spending commitment being requested for this  
activity. For instance, in its Closing Submission, Avon notes that, following the Board=s direction  
in the Power Outage Review, NSPI filed its 69 KV Right-of-Way Widening Assessment Report  
outlining in detail its proposed activities for 2006 by corridor and kilometer for widening the right-  
of-way along its transmission system .134 In the report, NSPI provided a budget of $500,000 for its  
request, which the Board notes is intended to be a capital expenditure rather than an operating  
expense. While this particular $500,000 expenditure is not within the scope of this rate hearing,  
Avon identifies this report as the basis for its argument that NSPI failed to set out any similar detail  
with respect to its proposed increase for vegetation management from $5.2 million to $10.4 million.  
[359] Likewise, the Consumer Advocate argues that NSPI=s application is deficient in this regard.  
In its Closing Submission, the Consumer Advocate highlights the response provided by NSPI to CA  
IR-37, wherein the Company states that the increased spending is to be directed to conducting a  
greater level of vegetation management, consistent with past practices to improve reliability. In its  
IR response, NSPI adds that no final decisions or commitments have been taken with respect to the  
additional monies until they are approved by the Board.  
[360] The Board observes that evidence to the same effect was given by witnesses for NSPI during  
the hearing. In cross-examination by Nancy G. Rubin, Counsel for Avon, Dan Muldoon, NSPI=s  
134Undertaking U-7  
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General Manager of Customer Operations for Transmission and Distribution, confirmed that the  
Company had not compiled the details of the proposed spending:  
Q.  
A.  
Now, have the specifics of the plan been set out anywhere?  
(Muldoon) In general we have put together elements of the plan to focus on more  
proactive reliability-based trimming, as well as sustainability. The specifics on span  
by span, feeder by feeder, we're currently gathering that data through our inspection  
programmes now to put the plan together.  
Q.  
A.  
And when do you anticipate that plan will be complete?  
(Muldoon) We'll have that plan complete probably by the end of this year for implementation  
in 2006.  
Q.  
A.  
So you're looking for approval of it now prior to the time that we have a chance to  
review the plan and the budgets and the work being done.  
(Muldoon) The plan that we have would be -- would fully support the 10.4 million  
dollar span that we have in our 2006 ---  
Q.  
A.  
My question had to do with the timing of it. You're looking for approval of spending,  
10.4 million dollar spending, prior to the time that we get to see the details of that  
spending.  
(Muldoon) That is correct.  
(Transcript, November 14, 2005, pp. 196-197)  
[361] Mr. Muldoon was further asked on cross-examination by Mary Ellen Donovan, Counsel for  
HRM, about NSPI=s proposed spending target in 2006 of 70% for the distribution system and 30%  
for the transmission system:  
Q.  
When you built that number, did you develop a document that showed the basis  
upon which you developed that number that could be provided in an undertaking  
here?  
A.  
(Muldoon) I believe we could. I think we have those dollars targeted towards the  
large programme elements. We wouldn't have specific feeder by feeder or segment  
by segment or span by span detailed data as of yet, but in general we would have a  
good idea where that money is to be directed to meet our customers' changing  
needs and expectation around storm-proofing the system.  
(Transcript, November 14, 2005, pp. 209-210)  
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[362] In her testimony, Nancy Tower, NSPI=s Chief Financial Officer, reasserted Mr. Muldoon=s  
view that the Company is confident about where the additional expenditures for vegetation  
management can be directed. In response to questioning by Mr. Merrick, she stated:  
...  
A.  
(Tower) Mr. Merrick, if I could, I was previously B before being Chief Financial Officer  
was Vice-President, Customer Operations, and had responsibility for vegetation  
management as part of that. One of the things the customers have told us and  
having sat through the storm hearing, it was clear to me, certainly, that customers  
wanted increased reliability in the province. We would have a list of every feeder in  
the province, perhaps even by feeder segment, numbers of customers on it and the  
reliability that that feeder is currently experiencing. We would also -- we would  
prioritize each year depending on how much vegetation spending we had, and we  
would cut the list at a certain point depending on where the spending was knowing  
how much reliability that would give us. To get more reliability, we had to do more  
spending. We know exactly where we would go on the next feeder, and the next  
feeder segment, and where in the province with the five million dollars ($5,000,000).  
So it's very clear to us and we have a plan that would probably span a number of  
years out.  
(Transcript, December 1, 2005, pp. 3227-3228)  
[363] In assessing the request for additional spending on vegetation management, it is instructive to  
consider the Board=s findings in the recent Power Outage Review. In that decision, the Board  
accepted various consultants= findings about vegetation management and its impact upon NSPI=s  
transmission and distribution systems.  
[364] In relation to the transmission system, Liberty concluded that NSPI=s transmission  
maintenance practices were substantially in accord with good North American utility practices and  
that these practices did not contribute to the structure failures or outages occurring during the  
November 2004 storm:  
[36]  
With regard to the maintenance and design of NSPI=s transmission structures,  
Liberty essentially found no areas of concern:  
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Liberty assessed NSPI=s design of the failed transmission structures and  
sky wires and found them in accordance with the appropriate standards. The  
wind and ice conditions in the November storm created loadings on the  
structures and sky wires that exceeded design loadings by at least 200  
percent. Liberty also found that NSPI=s transmission inspection program  
complies with good utility practices and that transmission maintenance  
substantially complies with good utility practices. Neither transmission  
system inspections nor maintenance contributed to the effects of the  
November storm. Liberty concluded that although tree contact caused some  
storm transmission outages, NSPI=s transmission vegetation management  
program is substantially consistent with good utility practices. NSPI needs to  
complete its program to widen and side-cut transmission system right-of-  
ways.  
(Exhibit N-19, p. 4)  
[37]  
Liberty found that NSPI=s efforts in this regard conformed with North American utility  
practice. It also stated:  
Liberty found no evidence that NSPI=s staffing, maintenance, or inventory  
practices had any appreciable effect on the severity of the outages caused  
by the November storm.  
(Exhibit N-19, p. 15)  
(Board Power Outage Review, August 5, 2005, para. 36-37)  
[365] During its inspection of the transmission system, Liberty made specific observations with  
respect to right-of-way clearance. In its report, Liberty stated that:  
Liberty observed that NSPI has numerous right-of-way issues to address, especially on its 69  
kV lines. During its aerial assessment of the NSPI transmission system, Liberty observed that  
about 10 km of 69 kV line L-5532 from Digby to Big Falls routes along the road. Side  
clearances on this section appeared to be less than the 10 m required for its 69 kV lines  
located on right- of ways. A tree caused an outage on this line during the November storm,  
and was the fifth and last interrupted transmission path to Annapolis Valley. This caused the  
interruption of all remaining load and hydro generation in the valley. In addition, Liberty  
observed other locations, particularly in the western part of the province, where NSPI had not  
yet trimmed the 69 kV and 138 kV right-of-ways to full width.  
(Board Power Outage Review, August 5, 2005, para. 44)  
[366] In its findings on the transmission infrastructure, the Board commended NSPI for its design,  
construction and maintenance practices. However, it noted Liberty=s concerns with respect to the  
right-of-way clearance relating to certain transmission lines:  
[64]  
Finally, the Board notes Liberty's comments regarding the completion of ROW  
clearance relating to certain transmission lines, particularly in the western part of the  
Province. Liberty stated that:  
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In some locations, NSPI's 69 kV and 138 kV lines do not center in the  
right-of-ways. In 2004, NSPI started widening right-of-ways up to 10 feet on  
its 69 kV system, with permission, to provide the standard clearance from  
the lines to the right-of-way edges. It expended about $146,000 in 2004 for  
69 kV right-of-way widening. It plans to spend about $350,000 in 2005 for  
right-of-way widening on radial 69 kV lines, those that most affect costumer  
[sic] service.  
(Exhibit N-19, p. 18)  
[65]  
Accordingly, the Board directs NSPI to file an assessment report, by November 30,  
2005, describing the work that has been or will be performed to implement the completion of  
the transmission ROW clearance, and giving a timetable and estimated cost assessment.  
(Board Power Outage Review, August 5, 2005, para. 64 - 65)  
[367] As a result of that direction by the Board, NSPI filed its 69 KV Right-of-Way Widening  
Assessment Report, which was filed in this hearing as Undertaking U-7.  
[368] With respect to NSPI=s distribution system, John Sherrod acted as the Board=s consultant.  
While not specifically addressing vegetation management, John Sherrod=s conclusions included:  
...  
3.  
The damages caused to NSPI distribution facilities by the subject storm are  
consistent with what would be expected with facilities in normal condition subjected  
to such weather factors.  
4.  
5.  
6.  
The NSPI distribution inspection processes, both routine and post-event, appear  
adequate and appropriate to good asset management.  
The damages resulting from the subject storm were not a result of any deficiency in  
NSPI inspection and maintenance processes.  
The staffing levels of NSPI power line technicians (PLTs ) as maintained for the past  
ten years and available at the time of the subject storm are within customary limits in  
the industry and did not have a negative impact on maintenance of NSPI distribution  
facilities or on storm outage response.  
7.  
The NSPI Customer Average Interruption Duration Index (CAIDI) has increased over  
the past ten years coincident with the PLT staffing level reduction, and this issue  
should be addressed.  
(Board Power Outage Review, August 5, 2005, para. 78)  
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[369] The Board accepted Mr. Sherrod=s assessment of the condition of NSPI=s distribution  
system and again commended NSPI for its efforts in constructing, inspecting and maintaining the  
distribution system. However, at paragraph 216 of its Power Outage Review, the Board noted that  
NSPI=s distribution system in the Digby County area and the western part of the province had not  
specifically been inspected. As a result of concerns expressed by customers from across the  
province during the hearing, the Board engaged Liberty to conduct field inspections of the areas  
referred to by members of the public and report their findings respecting the condition of NSPI=s  
distribution system to the Board before November 30, 2005.135  
135Board Power Outage Review, August 5, 2005, para. 234  
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[370] In the view of the Board, the results of the Power Outage Review provide a useful context for  
the assessment of NSPI=s request for a doubling of its vegetation management budget. Liberty=s  
report on NSPI=s distribution system has since been filed with the Board in late 2005. The Board is  
now awaiting a response to the report from NSPI. In the circumstances, the Board considers it  
appropriate to defer any additional spending on vegetation management for NSPI=s distribution  
system until a full evaluation is undertaken of Liberty=s report. While the Board is mindful that  
NSPI is able to identify feeders upon which such monies could be expended, the Board determines  
that such activities would be premature given the pending deliberations following the filing of  
Liberty=s recent report. The review of Liberty=s report will also provide NSPI with the opportunity  
to outline the Company=s estimates of the reduced outage and repair costs that can be anticipated  
from increased vegetation management (a measure of the program=s success recommended by PWC  
in its Report)136. Thus, in relation to vegetation management on NSPI=s distribution system, the  
Board does not approve any increase in spending for the test year. The current level of expenditure  
for the distribution system shall remain at $3.6 million.  
[371] With respect to additional spending to be directed to vegetation management on NSPI=s  
transmission system, the Power Outage Review did identify specific areas of concern. In light of the  
significance of NSPI=s transmission infrastructure, as well as the areas of concern outlined in the  
Power Outage Review, the Board approves the additional spending for vegetation management  
proposed by NSPI with respect to its transmission system. Based on NSPI=s response to  
Undertaking U-9 filed during this hearing, the Board infers that the level of increased spending  
136PWC Pre-filed Evidence, Exhibit N-84, p. 21  
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proposed for the transmission system is an additional $1.6 million. Accordingly, the Board approves  
this additional amount for vegetation management on NSPI=s transmission system, over and above  
what is already reflected in current rates (i.e., for a total of $3.2 million).  
[372] Accordingly, for the test year, the amount of spending for vegetation management approved  
by the Board shall be a total of $6.8 million ($3.2 million for the transmission system and $3.6  
million for the distribution system). In approving this amount, the Board takes into account the fact  
that NSPI has recently negotiated a 20% saving with respect to all vegetation management activities  
as a result of outsourcing the work to one third party contractor. This means that, in comparison to  
previous years, this approved budget should yield a 20% increase in services for the same cost.  
[373] NSPI has also requested an additional $1.3 million to improve communication with its  
customers. In its Power Outage Review, the Board directed NSPI to undertake various measures to  
improve its communications with customers, including improvements to its telephony technology,  
the conduct of a stress test on its system, reviewing the Acall overflow management system@, and  
developing a communications plan to improve the Company=s interaction with its customers  
respecting the reporting of power failures and the restoration of service.137 The Board also  
determined that a major problem during significant power failures was the inability of NSPI=s  
customers to advise the Company of power outages, to inquire about the problem, and to determine  
the estimated restoration time. The Board directed NSPI to report its progress on these various  
137Board Power Outage Review, August 5, 2005, para. 187 - 200  
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issues by September 30, 2005. The Company=s request for an additional $1.3 million stems, in part,  
from these issues raised during the Power Outage Review.  
[374] The need to improve NSPI=s HVCA and IVR telephone systems was highlighted in the  
Power Outage Review. The failure of these two systems contributed to many of the communication  
problems which arose during the November 2004 snow storm. Based on its findings during that  
Review, the Board determined that NSPI=s customers expect these systems to accommodate their  
needs during power outages. The Board approves the amount of $500,000 with respect to  
enhancements to the HVCA and IVR telephone systems, as well as the testing of the systems.  
[375] However, the Board is not satisfied that NSPI=s request for the remaining $800,000 is  
warranted with respect to increased customer research respecting outage communication processes,  
additional proactive communications with respect to storm preparedness and increased quality  
assurance in the customer service area. Both the Province and PWC questioned the annual nature of  
these requested expenditures, PWC adding that some of the expenses appeared to be one-time costs.  
While the Board concurs that some increased expenditure in these areas is justified, it does not  
accept NSPI=s view that an $800,000 increase is required on an annual basis, particularly in the  
context of the significant rate increase being requested by the Company. In these circumstances, the  
Board reduces the additional $800,000 amount for these remaining activities to $300,000 per year.  
[376] In summary, the Board approves $500,000 with respect to telephony technology  
improvements and $300,000 with respect to improved outage communication processes and  
increased quality assurance in the customer service area.  
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6.4  
Corporate Support Groups (excluding DSM)  
6.4.1 Submissions - NSPI  
[377] Corporate Support Groups include expenditures associated with providing services for  
regulatory compliance, accounting, internal controls, governance, administration, investor relations,  
human resource management, stakeholder communications, procurement, and information  
technology.  
[378] For the test year 2006, NSPI proposes a net increase in these costs by $7.3 million over the  
2005 Compliance Filing. The primary component of this proposed increase stems from the  
Company=s proposed increase of $5 million related to the Marketing and Sales Group and its  
Demand Side Management (ADSM@) initiatives. The Board=s discussion of the issues surrounding  
DSM are contained elsewhere in this decision. The remainder of the net increase related to the  
Corporate Support Groups is comprised of various other increases and decreases proposed to be  
allocated to various function groups falling under Corporate Support. During the hearing and in  
closing submissions, the intervenors focused their attention on a proposed net increase of $400,000  
requested for Investor and External Relations and Environment (AInvestor and External Relations@),  
as well as an additional $2.0 million sought with respect to Regulatory Affairs. In its report filed in  
advance of the hearing, PWC raised a third issue respecting a net increase of $470,000 being  
claimed by NSPI=s Finance Group for compliance with securities regulators.  
[379] With respect to Investor and External Relations, NSPI identified a $492,000 increase in  
advertising costs over 2005 Compliance expenditures, resulting in a net increase of $400,000 with  
respect to the Investor and External Relations Group. It indicated that this amount will be directed  
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to Acommunication designed to better engage and educate customers about issues important to the  
overall operation of the utility@. It identifies these issues as follows:  
The issues covered in this communication would include, but would not be limited to: DSM  
(energy efficiency and conservation); changes in environmental regulations, environmental  
progress; renewable energy; global energy prices; and storm preparedness. The functional  
delivery of the DSM program remains entirely within Customer Service.  
(Avon IR-20)  
[380] NSPI states that the $492,000 amount is allocated to various forms of communication,  
including $150,000 for ongoing development of the next generation of web-based interactive  
communications with customers and other stakeholders.  
[381] NSPI also proposes an increase of $2.0 million in spending for Regulatory Affairs of the  
Corporate Support Group, increasing its $2.6 million spending level in the 2005 Compliance Filing  
to $4.6 million for the 2006 test year. The Company asserts that the $2.0 million increase is  
comprised of additional Board assessment fees, additional NSPI and Board consulting and legal fees  
associated with Aincreased regulatory activity@and the additional cost of a consumer advocate.138  
In their testimony, witnesses for NSPI indicated that the $1.6 million increase is associated with the  
Company=s 2007 rate application, which it expects to file in 2006. A further amount of $400,000 is  
also claimed for an increase in the 2006 Board assessment.  
[382] In addition to the above $2.0 million increase, NSPI seeks to recover as part of the 2006 test  
year costs a further $2.0 million with respect to the costs of the present 2006 rate application  
conducted in 2005, and an increase of the Board assessment charge to NSPI in 2005. This $2.0  
million is included in the Corporate Adjustments account of the rate application. Noting that the  
138NSPI Application, Exhibit N-1, pp. 96-97  
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2006 rate application costs and the increased Board assessment for 2005 were not provided for in  
2005 rates, NSPI, in effect, seeks to defer the expenses from 2005 and include them as costs of the  
2006 test year. In NSPI=s view, this treatment is consistent with previous deferrals of operating  
expenses and allows the matching of the revenue (i.e., 2006 revenue) with the associated costs (i.e.,  
the 2006 rate hearing conducted in 2005 and the incremental portion of the Board assessment  
incurred in 2005).139  
139Province IR- 53; PWC IR-21; Exhibit N-1, p. 104  
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[383] NSPI also seeks a net increase of $470,000 to ensure regulatory compliance with the Ontario  
Securities Commission (AOSC@) following the OSC=s adoption of new governance and audit  
regulations contained in guidelines approved by the Canadian Securities Administrators in February  
2005. Both NSPI and Emera must adhere to these regulations, which require the Chief Executive  
Officer and the Chief Financial Officer to provide certification with respect to disclosure controls  
and internal controls respecting financial reporting. Moreover, the certification requires a more  
rigorous attestation process by external auditors.140  
[384] The additional compliance costs associated with the new OSC regulations total $941,000.  
This figure is comprised of $565,000 for consulting costs attributed to work needed to comply with  
the new governance regulations and $376,000 for external legal and audit costs associated with the  
review of the regulations.141 Half of the projected increase of $941,000 is to be allocated back to  
Emera through Corporate Support Transfers, leaving a net increase of $470,000 for NSPI.  
6.4.2 Submissions - Intervenors and PWC  
[385] Avon opposes both the $492,000 incremental increase with respect to advertising under  
Investor and External Relations, as well as the recovery, in the 2006 test year, of the costs for the  
hearing held in 2005 respecting a rate increase for 2006.  
[386] With respect to the proposed $492,000 incremental increase for Investor and External  
Relations advertising, Avon submits:  
140NSPI Application, Exhibit N-1, p. 95; PWC IR-25  
141NSPI Application, Exhibit N-2, Appendix B, p. 7 of 52  
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218.  
It seems evident that there is some element of double-counting given that NSPI is  
also seeking $5 million associated with DSM which has, as its largest component,  
communications and promotions as well as an incremental increase of $4 million for storm  
response which likewise has, as a large component, communications, (although denied by  
NSPI).  
219.  
While a half million dollars may not seem like much in the grand scheme of Nova  
Scotia Power=s overall revenue requirements, it is indicative of the cavalier approach which  
NSPI has adopted in putting together its revenue requirement. Intervenors are unable to  
assess the reasonableness of the expenses and particularly, where line items such as  
advertising suggest duplication and a significant increase over prior spending, it is  
respectfully submitted that NSPI must do more to discharge its burden to show that these  
expenses are reasonable and properly chargeable.  
220.  
If NSPI wishes to spend money on communications which have the effect of  
promoting NSPI and generating goodwill in the community, then it may do so. However,  
similar to the Board=s decision with respect to sponsorships, as reaffirmed in the 2002 rate  
case, this should not be included in the revenue requirement to be recovered from  
ratepayers.  
(Avon Redacted Closing Submission, p. 46, para. 218 - 220)  
[387] In its Closing Submission, Avon also opposes NSPI=s proposed recovery of its costs for both  
the 2005 and 2006 rate applications in the same test year.  
[388] Avon argues that it is Amanifestly unfair@to ask ratepayers, in the same test year, to bear the  
burden of the costs associated with both the 2006 rate case (held in 2005) and 2007 rate case  
(contemplated for 2006). In response to NSPI=s assertion that this can be treated as an  
Aamortization of deferred operation costs@, Avon states that a request for the deferral of costs for a  
rate hearing is unprecedented. Citing Philadelphia Electric Co. v. Pennsylvania Public Utilities  
Commission, 502 A(2d) 722 (1985), Avon submits that a utility is not entitled to seek recovery of a  
shortfall in a prior rate hearing=s expense line item unless such expenses were extraordinary,  
unanticipated and of a non-recurring nature.142 Avon observes that regulatory expenses are clearly a  
line item for which NSPI sought and received rate revenue in a prior test year (i.e., 2005) and that  
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the costs for the 2006 rate application (held in 2005) were not unforeseen, extraordinary or non-  
recurring.  
142Avon Redacted Closing Submission, pp. 44-45  
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[389] The Province also opposes the recovery of $2.0 million in the 2006 test year with respect to  
regulatory expenses incurred in 2005 for 2006 rates. It questions NSPI=s submission about  
matching expenses with revenues in the same test year. Further, the Province suggests that the costs  
of a rate application should be Alevelized@over the number of years the rates resulting from that  
application are expected to remain in effect. Otherwise, it observes that the full costs of a rate  
application could remain in rates for future years in which no rate case is undertaken.143  
[390] The proposed increase related to regulatory costs is also opposed by the CME. In addition to  
its view that the costs of two annual rate applications should not be recovered in the same test year,  
the CME echoes Avon=s concern that the proposed increase in costs should be fully documented  
and justified.  
[391] Finally, both Avon and the Province submit that, if the Board considers it appropriate to  
approve the expenses occurred in 2005 for recovery in 2006, the same treatment should be accorded  
to the rate application being contemplated by NSPI in 2006 with respect to 2007 rates.  
143Province Redacted Closing Submission, para. 63-64  
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[392] PWC reviewed NSPI=s request for a net increase of $470,000 relating to its compliance with  
the new OSC regulations. While PWC suggested that some of the one-time documentation and  
setup costs could be deferred over the period of benefit, it did not object to inclusion of such costs in  
the test year given their relative magnitude. However, it noted that on July 29, 2005, following the  
filing of NSPI=s application for this rate hearing, a one year delay in the implementation of the  
regulations was announced. In a response to PWC IR-43 respecting this delay in the implementation  
of the regulations, NSPI confirmed that it intends to complete the documentation and testing of its  
internal controls in 2006, as planned, but that it may defer the increase in audit fees that NSPI will  
incur to 2007. PWC submitted that these cost deferrals should be estimated and excluded from the  
2006 test year.144  
6.4.3 Findings  
[393] In addition to the issue of the proposed increase for DSM, the intervenors raised three issues  
with respect to the proposed spending increase for Corporate Support Groups: 1) the incremental  
increase of $492,000 related to Investor and External Relations=communication and advertising  
expenses, and 2) the $2.0 million proposed increase related to Regulatory Affairs. PWC raised a  
third issue, 3) the necessity of including all of NSPI=s request of $470,000 for increased regulatory  
compliance respecting more stringent governance and audit requirements.  
144PWC Pre-filed Evidence, Exhibit N-84, p. 19  
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[394] In response to Avon IR-20, NSPI confirmed that the proposed increase of $492,000 for  
advertising is to be directed to forms of communication which would Abetter engage and educate  
customers about issues important to the overall operation of the utility@. It noted that the issues to  
be covered include matters relating to DSM, changes in environmental regulations, renewable  
energy, global energy prices and storm preparedness.  
[395] In the opinion of the Board, most of the issues sought to be canvassed by NSPI in its  
increased advertising relate to activities already contemplated in other sectors of the Company=s  
operations and, as such, constitute an overlapping or double counting of expenses claimed elsewhere  
in rates. For instance, communications related to storm preparedness are, and should be, part of the  
proposed spending increase for storm response under Customer Operations and all communication  
expenses associated with DSM should be budgeted within the DSM envelope. Further, the Board  
concurs with Avon=s submission145 that other expenses related to promoting the Company=s  
corporate image and enhancing its goodwill in the community should not be included in the revenue  
requirement being sought from customers.146  
145Avon, Redacted Closing Submission, para. 220  
146Board 2002 Rate Decision, para. 138-139  
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[396] Thus, the Board denies the Company=s request for a $492,000 increase for advertising  
activities carried out by the Investor and External Relations group, and the Board directs that  
OM&G expenses be reduced accordingly.  
[397] NSPI seeks a $2.0 million increase for the 2006 test year to cover the estimated regulatory  
costs associated with an increase in the 2006 Board assessment, and a rate application expected to be  
filed in 2006 with respect to 2007 rates. In addition, under the Corporate Adjustments category,  
NSPI also seeks a further $2.0 million for regulatory expenses incurred in 2005 associated with the  
present rate case and the increased 2005 Board assessment. The Board considers it appropriate to  
consider these requests together.  
[398] NSPI asserts that the $2.0 million amount being claimed for each of the present and  
upcoming rate cases, as well as the increased Board assessment for 2005 and 2006, are not currently  
reflected in rates. The 2005 Compliance Filing shows that $2.6 million is allocated for Regulatory  
Affairs spending. In its application, NSPI states that the $2.0 million increase is comprised of  
additional Board assessment fees, additional NSPI and Board consulting and legal fees associated  
with Aincreased regulatory activity@and the additional cost of a consumer advocate.147  
[399] The Board has serious reservations about NSPI=s request to defer the expenses incurred in  
2005 with respect to the present rate case and the increased Board assessment for 2005. While the  
Board is mindful that expenses for the hearing were incurred by the Company with respect to 2006  
rates, it has been NSPI=s practice to write-off these expenses in the year in which they were  
147NSPI Application, Exhibit N-1, p. 97  
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incurred. In the Board=s opinion, it is not reasonable to burden ratepayers with the cost of two rate  
hearings and two increased Board assessments in the same test year, which would be the case were  
the Board to permit NSPI to roll such costs forward into the 2006 test year.  
[400] In the case of NSPI, it appears that the costs associated with rate applications will be of a  
recurring nature. While NSPI has not filed a rate application in each and every year, such  
applications are becoming rather common and, if an application is filed in 2006 with respect to 2007  
rates (as witnesses for NSPI have indicated is likely), then it will mark the fourth such application  
since 2002. In fact, in presentations to outside parties, NSPI has anticipated annual rate filings, at  
least until 2008.148 Further, given the environment of rising fuel costs over the past few years, the  
possibility of rate applications, including one in 2005 for the 2006 test year, could, in the opinion of  
the Board, have reasonably been foreseen by NSPI and, therefore, should have been estimated in the  
2005 test year figures. Lastly, NSPI=s regulatory costs were included as an expense line item, for  
which the Company sought and received revenue from rates. Such expenses typically come in above  
or below projections. The Board does not require NSPI to refund any surplus related to a particular  
expense category149, nor does it consider it appropriate for NSPI to seek a deferral of any shortfall in  
relation to an expense item which could have been reasonably anticipated.  
148NSPI presentation to Standard & Poor=s, Exhibit N-30, SEB IR-95, Attachment 5, p. 16  
149For example, NSPI=s interest expense is expected to be about $5 million less than projected in  
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2005, see Transcript, November 22, 2005, p. 1024  
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[401] For the above reasons, the Board denies NSPI=s request to defer the costs of the 2005 rate  
hearing to the 2006 test year. Accordingly, this proposed deferral under the Corporate Adjustments  
category is not approved and the Compliance Filing for 2006 shall be adjusted to reflect this finding.  
[402] However, the Board does approve NSPI=s request for additional spending of $1.6 million  
associated with the anticipated rate application to be filed in 2006 for 2007 rates. In doing so, the  
Board is mindful that the approved increase of $1.6 million for Regulatory Affairs is a significant  
increase and, as noted by the Province, the full costs of a rate application will be included in rates in  
future years even when no rate case is undertaken.  
[403] Upon review, it appears that the Board=s annual assessment currently reflected in rates is  
$593,000 (the 2000 assessment)150 and that, for the year ending March 31, 2005, the annual  
assessment increased to $997,457. This increase is not currently reflected in rates. The Board  
approves the increase of $400,000 for inclusion in 2006 rates with respect to the March 31, 2006  
year end. However, for the reasons explained immediately above, the Board denies NSPI=s request  
to recover the increased assessment relating to March 31, 2005. In support of this conclusion, the  
Board observes that NSPI would have had an estimate of the annual assessment for March 31, 2005,  
prior to the filing of its 2005 rate case, which was filed on May 28, 2004151, and revised on June 23,  
2004152. It should be noted that the annual assessment has increased gradually since 2000.  
Consequently, it was certainly possible for NSPI to have made a reasonable estimate of the 2005  
assessment when it applied to increase rates for that year.  
150NSPI Application, Exhibit N-1, p. 97  
151Board 2005 Rate Decision, March 31, 2005, para. 7  
152Board 2005 Rate Decision, March 31, 2005, para. 4  
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[404] New governance and audit regulations adopted by the OSC will result in higher regulatory  
compliance costs. In its application, NSPI projected these costs to be a net amount of $470,000 for  
the 2006 test year. After NSPI=s application was filed, a one year delay in the implementation of  
these governance and audit regulations was announced. In response to PWC IR-43, NSPI stated that  
it intended to complete the documentation and testing of its internal controls in 2006, as originally  
planned. However, it indicated that it may defer the increase in audit fees to be incurred by the  
Company to 2007. PWC recommended that NSPI estimate the amount of this cost deferral and that  
such costs be excluded from the 2006 test year.153 The Board concurs with the opinion of PWC. It  
directs that half of the proposed net increase be deferred to 2007, resulting in a net increase approved  
for this activity of $235,000 ($470,000 less 50% recovered from Emera).  
[405] In conclusion, the Board approves the increased OM&G spending proposed by NSPI for  
Corporate Support Groups in the amount of $7.3 million over the 2005 Compliance Filing, subject to  
reductions of $492,000 respecting advertising and communication expenses by the Investor and  
External Relations group; $4.45 million with respect to DSM as set out elsewhere in this decision;  
and a net amount of $235,000 respecting implementation of new governance and audit regulations  
by the OSC.  
[406] While the Board approves the $1.6 million expenditure increase under Regulatory Affairs  
respecting a 2007 rate case expected to be filed in 2006, the expenses for the rate hearing held in  
2005 are denied under Corporate Adjustments. Further, for the same reasons, the increase of  
153PWC, Pre-filed Evidence, Exhibit N-84, p. 19  
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$400,000 relating to the increased Board assessment for 2005 is denied. However, the estimated  
increase of $400,000 for 2006 is approved.  
6.5  
Corporate Adjustments  
6.5.1 Submissions - NSPI  
[407] This category comprises expenses which are not specifically assigned to a business unit or  
functional area, including year-end payroll accrual, incentives, deferred severance, capital overhead  
contributions and pension expenses. While there is a proposed decrease of $500,000 for Corporate  
Adjustments from $13.6 million (2005 Compliance Filing) to $13.1 million for the 2006 test year, a  
significant component of this expense category relates to pension expense which is proposed to  
increase from $26.0 million (2005 Compliance Filing) to $31.7 million for the 2006 test year. This  
represents an increase of $5.7 million in pension expense. The basis for this increase is explained by  
the Company in its application:  
Pension expense is projected to be $31.7 million in 2006 compared to $26.0 million in 2005C,  
an increase of $5.7 million. The primary reason for the increase in pension expense is the  
adoption of updated mortality tables used by actuaries to determine pension funding and a  
lower discount rate used to value outstanding obligations. The updated mortality  
assumptions show that on average, people are living longer, which results in pensions being  
paid for longer periods of time. This shows up as an increase in pension expense.  
Additionally, the discount rate estimated is presently 5.5% versus 5.75% in 2005C. NSPI's  
actuary, Paul Chang of Morneau Sobeco has provided the Company with the appropriate  
discount rate for CICA 3461 reporting purposes. Based on single "A" bonds, the current  
discount rate as of May 31, 2005 that would be used to determine CICA 3461 expense for  
NSPI is 5.5%.  
(Exhibit N-1, p. 105)  
[408] In PWC IR-23, NSPI provided a reconciliation of the pension expense from the 2005  
Compliance Filing to the 2006 test year, accounting for the factors described above:  
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Pension Expense - Reconciliation of Benefit Cost  
2004 Actual Benefit Cost  
$21.9 M  
Exclude impact of Amendment No. 12  
Change in discount rate (6% to 5.75%) based on AAA@corporate bonds  
Other factors  
$ 0.9 M  
$ 2.7 M  
$ 0.5 M  
2005 Compliance Benefit Cost (prior to Amendment No. 12)  
$26.0 M  
Include impact of Amendment No. 12  
Change in definition of high quality debt instrument used to determine  
discount rate from AA corporate to A corporate  
$(1.9) M  
$(2.7) M  
$21.4 M  
2005 Forecast Benefit Cost  
Change in discount rate (6% to 5.5%) based on AA@corporate bonds  
Change in mortality table  
Other factors  
$ 5.4 M  
$ 4.5 M  
$ 0.4 M  
2006 Forecast Benefit Cost (per Rate Case)  
$31.7 M  
6.5.2 Submissions - PWC and Intervenors  
[409] PWC was retained by Board Counsel to review, among other issues, the pension expense. In  
its report filed as Exhibit N-84, PWC concluded that the policies followed by NSPI in forecasting  
pension expense for the 2006 test year are reasonable:  
Changes in two major actuarial assumptions account for most of the $10.3 million increase in  
pension expense in 2006.  
Effective in 2006, NSPI=s assumptions with respect to mortality of pension plan beneficiaries  
is based upon an updated mortality table giving recognition to the fact that people are living  
longer and will draw pension benefits for a longer time. This is a fairly common, recent  
change made by other companies with defined benefit pension plans and was approved for  
adoption by the Canadian Institute of Actuaries in 2005. We consider the change reasonable  
and appropriate.  
The total impact of this change upon the pension benefit obligation is estimated to be $26.4  
million. This higher liability will be expensed over 10 years and in 2006, $4.5 million will be  
recognized in pension expense.  
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At December 31, 2005 a discount rate will be assumed for purposes of valuing the pension  
and post-retirement benefit liability at December 31, 2005. For regulatory and test year  
purposes, NSPI has assumed a rate of 5.5% will apply for 2006, based upon rates at May 31,  
2005. This 0.50% reduction in the discount rate from 2005, causes an overall increase in the  
liability of $51.6 million and an increase in pension expense in 2006 of $5.4 million.  
Management also makes assumptions concerning expected remaining life of employees,  
retirement age, salary increases, mortality, etc. NSPI=s actuary has provided an opinion  
respecting the reasonableness of these assumptions for the 2006 test year.  
For general purpose financial statements and rate regulation purposes, pension expense is  
being measured in accordance with generally accepted accounting principles...  
. . .  
Discount Rate  
The discount rate used to determine the present value of liabilities in the pension plan and the  
current service cost for each period has decreased from 5.75% in the 2005 rate case to  
5.50.% in the 2006 test year. This 2006 assumption was based on the interest rate on high  
quality bonds at May 31, 2005. The discount rate applicable to NSPI=s 2006 pension  
expense will be determined based upon market interest rates on high quality bonds as at  
December 31, 2005. Since May, 2005, bond yields have decreased by 25 to 50 basis points  
and forecasts indicate further declines in the months ahead.  
Thus, the discount rate used of 5.50% for the Test Year is, in our opinion, likely at the high  
end of the current range of 5.00% to 5.50%. The lower the discount rate the higher the  
liability, and the higher the expense. Lowering the discount rate also results in an initial  
actuarial loss on the accrued benefit obligation, which must be included for amortization into  
expense.  
...  
CONCLUSION  
Major assumptions with respect to expected rate of return on assets and forecasted discount  
rate for liability valuation are at the high end of reasonable ranges. Reductions in either of  
these rates would result in higher pension expense and ultimately a higher rate request. In  
our opinion the policies followed by NSPI in forecasting pension expense for the Test Year  
are reasonable.  
(PWC, Pre-filed Evidence, Exhibit N-84, pp. 10-13)  
[410] The Board did not receive any comment from the intervenors on the pension expense issue.  
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6.5.3 Findings  
[411] In support of its proposed increase for pension expense, NSPI filed an actuarial report  
outlining the basis for this increase. PWC, the Board=s consultants, have reviewed the actuary=s  
analysis and conclusions. Following its review, PWC filed a report stating that the pension expense  
is being measured in accordance with generally accepted accounting principles, that the assumptions  
being made by NSPI with respect to pension expense are reasonable and that the policies followed  
by NSPI in forecasting pension expense for the 2006 test year are reasonable and appropriate.154  
[412] No significant concerns were raised by any of the intervenors at the hearing.  
[413] In the circumstances, the Board accepts the evidence of NSPI and PWC that the forecasted  
pension expense for the 2006 test year is reasonable. The Board approves the increase in the amount  
of the pension expense from $26.0 million in the 2005 Compliance Filing to $31.7 million for the  
2006 test year, an increase of $5.7 million.  
[414] With respect to the remainder of the Corporate Adjustments sought by NSPI, the Board  
approves all of the said adjustments, except the proposed deferral of $2.0 million associated with  
regulatory expenses incurred by the Company in 2005, as discussed in the preceding section.  
Accordingly, the Board directs NSPI to reduce the Corporate Adjustments budget from the proposed  
amount of $13.1 million to $11.1 million for the 2006 test year.  
154PWC, Pre-filed Evidence, Exhibit N-84, pp. 9-13  
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6.6  
Summary of OM&G Findings  
[415] The following table contains the disallowances made by the Board with respect to OM&G:  
OM&G DISALLOWANCES  
(Dollars in Millions)  
Power Production  
Succession planning  
Subtotal  
$ 0.8  
$0.8  
$4.3  
$5.2  
Customer Operations  
Vegetation management  
Communication processes  
Succession planning  
Subtotal  
$3.6  
0.5  
0.2  
Corporate Support  
DSM  
$4.45  
0.49  
0.24  
Advertising costs  
OSC compliance  
Subtotal  
Corporate Adjustments  
2005 Regulatory costs  
Subtotal  
$2.0  
$2.0  
TOTAL  
$12.3  
[416] A summary of the overall impact of the Board=s findings respecting OM&G is shown in the  
following table compiled by the Board:  
TOTAL OM&G COSTS - Approved increases  
(Dollars in Millions)  
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2005C  
2005F  
2006  
Proposed  
Board  
Disallowance  
2006  
Board  
Approved  
Power Production  
Customer Operations  
Corporate Support  
Corporate Adjustments  
Total OM&G  
$66.0 M  
65.3 M  
$70.4 M  
67.6 M  
36.8 M  
5.6 M  
$75.3 M  
77.0 M  
$0.8 M  
4.3 M  
$74.5 M  
72.7 M  
37.1 M  
44.4 M  
5.2 M  
39.2 M  
13.6 M  
13.1 M  
2.0 M  
11.1 M  
$182.0 M  
$180.4 M  
$209.8 M  
$12.3 M  
$197.5 M  
[417] Thus, the Board approves an increase in OM&G expenses from $182.0 million (2005C) to  
$197.5 million for the 2006 test year.  
6.7  
OM&G - Operations Review  
6.7.1 Submissions - NSPI  
[418] For the 2006 test year, OM&G expenses are proposed to increase from $182.0 million in the  
2005 Compliance Filing to $209.8 million for 2006, an increase of $27.8 million (15.3%). As  
indicated above, the Board reduced the 2006 test year expenses to $197.5 million, thereby reducing  
the increase to 8.5%.  
[419] NSPI maintains that it is effectively monitoring its OM&G costs. It states that OM&G  
expenditures have been stable over past years as base costs have been maintained on a relatively flat  
basis through a variety of cost containment measures. In NSPI=s submission, the increases proposed  
for 2006 are driven by new investments.155  
[420] NSPI also notes that the Company=s success in managing its OM&G costs is supported by  
earlier reports filed with the Board in 2003 and 2004. It points out that these reports provided details  
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with respect to various aspects of its OM&G management, including financial processes and  
procedures for controlling expenditures, cost containment strategies, an overview of OM&G  
expenditures by type, an analysis of OM&G expenditures by operating units, and comparisons to  
external benchmarks. It maintains, as stated in its report filed on September 2, 2004:  
NSPI=s OM&G performance benchmarks extremely well when compared to its Canadian  
peers, as demonstrated in this report.156  
[421] NSPI outlined various cost containment strategies undertaken by the Company to control  
OM&G expenses, including improved matching of resources to the work required, ensuring that the  
most competitive resources are used to complete tasks, investing for the lowest long term cost,  
setting targets and conducting tracking to achieve continuous improvements.157  
[422] During the hearing, the Policy Panel described NSPI=s approach to managing its OM&G  
costs in response to questions posed by Mr. Grant:  
Q.  
A.  
Do your customers wish to see NSPI increase its efficiencies and productivity?  
(Tedesco) I think they have a right to expect that,and I think the record is clear that,  
in fact, over the last several years that's precisely what we have done.  
Q.  
In your budgeting process, do you indicate to your managers targets which you  
would like to see them hit in terms of reducing costs?  
155NSPI Redacted Closing Argument, p. 65  
156NSPI Application, Exhibit N-1, p. 72  
157NSPI Application, Exhibit N-1, pp. 73-77  
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A.  
(Tower) Having worked for Mr. -- both Mr. Huskilson and Mr. Tedesco as  
Vice-President of Customer Operations and being responsible for virtually half of the  
costs at Nova Scotia Power, I'd like to give you a bit of flavour of budgeting and the  
kind of culture that exists at Nova Scotia Power, and I think this follows on -- Mr.  
Chairman, follows on a bit from your question to Mr. Blunden yesterday. So -- and  
just by way of example, back in the fall of 2003 would have been a typical budget  
round, as we would call it. We were under significant pressure to reduce costs. And  
at that time, I would have been working directly for Mr. Huskilson. And I, like the  
other Nova Scotia Power executive, would have been pushed pretty hard to come up  
with cost savings as much as we possibly could. Mr. Tedesco was arriving in  
January and we wanted to make sure that we had a budget that we felt was as  
stretchy, is a word that we would use, as it could possibly be. And so we put  
something together that we thought was challenging for us and would be challenging  
for our teams. In January, 2004, Mr. Tedesco arrived and his -- the first thing that he  
did was ask us to cut those OM&G costs even further. And while we had -- you  
know, we had believed that we had cut as far as we possibly could, we had to look  
for even more savings as a result of Mr. Tedesco's direction. And we did -- we did  
look for those and we did get them. Things in my organization such as putting a  
single power technician in a truck, for example, and putting a shift on and using the  
truck for two shifts is something that we've done. Looking at automatic meter reading  
to determine whether it makes sense. Looking at sole sourcing our vegetation  
contract. I would tell you that pursuit of OM&G savings is not an event at Nova Scotia  
Power. It is just something that we do all the time. And, in addition, certainly our last  
general increase for staff overall would have been in January, '03. So we're asking  
our staff -- we're asking our managers and our staff to do this at a time when we've  
held their salaries fairly constant. So I just wanted to give that flavour because it is  
something that we are -- and with the cost pressures that we face as a result of our  
fuel increase, it is something that we've lived with and we've continued to look for  
each and every day that we work there. And I would say we do balance that, though,  
with customer service to make sure that we don't go any further than we need to and  
ensure that we provide the customer service that we need. One of the things that  
we've done is to understand very clearly our unit costs and understand our customer  
service levels and understand when we take costs out what that does to service. And  
so it is -- it does become a balance, but at the end of the day I would tell you and if  
you'd ask many of the people that worked for me, cost saving is something that we  
do. And I have continued that with me as I -- in my role as Chief Financial Officer, to  
ensure we're in a -- you know, we're budgeting again this year. This is the time of  
year that we do it. And certainly that philosophy would ring loud and clear.  
A.  
(Tedesco) I would just add to that that Mr. Merrick asked me, and I don't know if you  
were in the room at the time, Mr. Grant, whether or not there were additional things  
that we could do this year. And I think my answer was something to the effect that  
this year in particular we have all the incentive we need to do whatever we can to  
control costs. And it was my judgment that controlling costs further from where they  
currently exist would cause deterioration in the service, and I still hold that judgment.  
[Emphasis added]  
(Transcript, December 1, 2005, pp. 3065-3069, emphasis in original)  
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[423] NSPI submits that a special cost reduction initiative or exercise was not specifically  
undertaken in anticipation of this rate application because of its existing cost containment and  
control measures, which it describes as significant.158  
6.7.2 Submissions - Intervenors and PWC  
[424] A number of intervenors expressed concern about the proposed increase in OM&G costs. In  
its Closing Submission, Avon asked the Board to Aengage management consultants to review  
NSPI=s control of its OM&G expenses with a view to identifying best utility practices and further  
potential savings.@159 Avon suggested that this would be an opportune time to conduct such a  
review, given the size of recent rate requests and the fact that the Company anticipates further rate  
applications in 2006 and 2007.  
[425] The Consumer Advocate also expressed disappointment about NSPI=s alleged failure at the  
hearing to show that it had taken reasonable and necessary steps to control costs and to demonstrate  
that the increased expenditures are justified:  
... NSPI argues that it has discharged the burden of showing that it has taken reasonable and  
necessary steps to control costs and to ensure that the increased expenses being sought for  
recovery in rates are justified.  
What is missing in the testimony of the NSPI witnesses and in the final submission is any  
description of a procedure set up by the Company to screen, evaluate and prioritize whether  
158NSPI, Redacted Closing Argument, p. 69  
159Avon, Redacted Closing Submission, para. 166  
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the increased expenses are necessary and justified. For example, it would be reasonable for  
a company, seeking to increase its prices, to establish some process internally to evaluate  
the need for increased prices. All that the Board is left with in this application is evidence of  
the expenses for which recovery is sought. There is no basis to assess why those expenses  
were chosen, what other possible expenses were excluded and who and how the need for  
the expenses was evaluated.  
NSPI should be put on notice that in future applications in which it is seeking recovery of  
additional expenses, it will be expected to show an internal assessment process to verify the  
need for the amount of the expenses.  
(CA, Redacted Rebuttal Submission, para. 24-26)  
[426] While other intervenors did not specifically request a review or report with respect to the  
control of OM&G expenses, a few of the intervenors expressed concern about the necessity and  
justification for some of the increases, to the extent that they asked the Board to closely monitor the  
spending of the Company with respect to its activities.160  
[427] In a report filed on behalf of Board counsel, PWC expressed concern about NSPI=s OM&G  
costs going forward into future years. It noted that the OM&G cost per customer, in constant  
dollars, is projected to increase by over 12.5% from $383.4 million in the 2005 Compliance Filing to  
$431.6 for the 2006 test year.161  
160Province Redacted Closing Submission, para. 58 (Enhanced Storm Response), para. 59  
(Vegetation Management) and para. 60 (Telephony/Communications); CME Redacted Closing  
Submission, para. 24 (Vegetation Management & Storm Response) and para. 25 (Regulatory Costs)  
161PWC, Pre-filed Evidence, Exhibit N-84, p. 14  
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[428] Noting that NSPI failed to provide requested information respecting OM&G costs for 1996 -  
2003 and forecasts for 2007 - 2008, PWC stated:  
Given such limitation, we are unable to comment on the reasonableness of the 2006 level of  
OM&G cost per customer or in total, as comparisons with the historical or forecasted future  
trends are an important indicator in that regard. In particular, we have not been able to  
establish whether certain of the 2006 forecast OM&G costs are one year >spikes=in costs or  
whether they are expected to continue at 2006 levels going forward.  
As noted above, NSPI has asserted that 2007 and 2008 OM&G costs are expected to  
continue at or above 2006 levels. Should the growth in customer base remain low, this  
statement suggests possible future increases in OM&G per customer in the near term.  
The lack of availability of forecasts for 2007 and 2008, the fact that NSPI does not have  
detailed OM&G forecasts, the very high level forecast provided in response to PwC IR 22  
along with the underlying stated assumptions, as well as the significant increase in the  
forecast filed, all raise concern about the level of OM&G costs going forward.  
Conclusions  
We believe that it would be prudent for NSPI to provide, in support of future rate cases,  
detailed five year forecasts of OM&G costs. The review of such forecasts, we believe, would  
increase overall transparency, and allow the Board to see the quantification of certain  
forward-looking plans and programs such as capital vs. maintenance plans for each of the  
production facilities, DSM costs, regulatory costs, vegetation management and other storm  
response costs. It will also identify expected problem area where cost control measures may  
be implemented in a proactive manner.  
We also recommend, due to the sharp increase in OM&G costs and OM&G costs per  
customer, that NSPI undertake a detailed benchmarking study to compare its costs, by  
category, to the costs being incurred by other similar utilities.  
(PWC, Pre-filed Evidence, Exhibit N-84, pp.15-16)  
6.7.3 Findings  
[429] In past decisions, the Board has expressed concern about the control of OM&G expenses by  
NSPI. In its 2002 rate decision, the Board stated:  
[133]  
The Board has significant concerns with respect to whether NSPI has  
reduced corporate expenses to the fullest extent feasible and whether there are adequate  
controls on spending.  
[134]  
The Board=s authority in this area is found in Sections 42(2) and 45(1) and  
(2) of the Act which are set out earlier in this decision. The difficulty faced by the Board is that  
there is simply insufficient information available to determine whether the expenses outlined  
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in Appendix 1 of Exhibit N-1 are appropriate to be charged to ratepayers and are as low as  
prudently possible. NSPI is requesting ratepayers to bear these and other costs through a  
significant increase in electricity rates. It is, therefore, incumbent on the utility to satisfy the  
Board, through the public hearing process, that ratepayers=money is wisely and frugally  
spent. No such assurance is evident from the information which has been filed.  
[135]  
Further, the Board is concerned that NSPI=s internal budgeting procedures  
are not sufficiently thorough to ensure expenses are as low as possible.  
...  
[136]  
The Board believes that it is incumbent on NSPI management to be able to  
demonstrate that it has made every effort to operate on a cost efficient basis when it seeks to  
increase electric rates in Nova Scotia. Intervenors have raised valid questions concerning  
certain expenses. NSPI has not provided an adequate response. As a result, the Board is  
not satisfied that NSPI management has made every reasonable effort to eliminate  
unnecessary expenses.  
[137]  
Further, the Board understands that a "benchmarking" process is utilized by  
NSPI in setting overall spending levels. While this is a useful procedure, it should not be  
used to the exclusion of other methods of determining the appropriate level of expenses,  
including a careful and exhaustive review of NSPI=s operating expenses in an endeavour to  
ensure that it is operating as efficiently as possible.  
...  
[140]  
The Board=s concern in this regard goes beyond the present filing which  
projects NSPI=s 2002 test year expenses. It appears from this rate proceeding that while  
overall OM&G costs have not increased appreciably in the six years since the last rate  
hearing, certain corporate expenses have increased significantly. The Board notes that there  
are no studies, evidence of internal management reviews, or details of cutbacks on OM&G  
expenses on file with the Board. The Board believes there is a pressing need to demonstrate  
that cost reductions at NSPI affect the higher levels of the company as well as lower levels.  
[141]  
In view of the Board=s concerns in this regard, the Board has determined  
that NSPI shall undertake a detailed review of the current level of OM&G expenses and  
submit a report to the Board which demonstrates that NSPI is operating as cost-efficiently as  
possible. After examining the report, the Board will determine if a further study is required. If  
further action is required, the Board may appoint an independent consultant to perform the  
study.  
(Board Decision, October 23, 2002, para. 133-141)  
[430] During his testimony during this hearing, Mr. Huskilson reiterated the approach taken by  
NSPI in the review of its costs:  
Q.  
(Merrick) ... earlier about steps that you were taking to cut costs and expenses. Do  
you agree with that as a component --that that is part of what should be -- that that is  
a component that should be in every application for a rate increase, that is, that the  
company has -- puts forward the steps that it has taken to minimize its own expenses  
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and also to minimize the requirement for increased rates? Do you agree that that  
should be, from here on in, a component of an application?  
A.  
(Huskilson) Well, I would say is I think the -- especially the operating maintenance  
and general costs, but generally all of the costs of the company need to, I think, have  
two things happen. No. 1, I think they have to have a regular and solid review, which  
is something that we clearly did, in my view, in the last rate hearing. As well, the  
company has worked to report appropriately on those costs and continue to report on  
those costs. I don't know if that's something that we have to do every time we come  
before a rate -- a revenue requirement review, and the reason I say that is because  
there are ways to look at whether the company is doing a good job in that area,  
things like bench marking and looking at where the company sits against other  
companies who do the same kind of work. So I think there are mechanisms in which  
that can be reviewed. But I would say that it is very important that the costs are  
reviewed in great detail on an ongoing basis and that there is a special review at  
appropriate time frames.  
(Transcript, December 1, 2005, pp. 3219-3220)  
[431] The Board questioned the Finance Panel about the Company=s review of OM&G costs in the  
context of NSPI=s request for a large rate increase:  
Q.  
(Chair) NSPI is coming to the Board seeking a rate increase, an average rate  
increase of 13 percent. This is after a rate increase last year. So would you agree  
that in this situation NSPI has a special responsibility to review all areas of operating  
costs to see whether or not any cost efficiencies can be achieved?  
(Blunden) Yes, I would agree with that.  
A.  
Q.  
A.  
Was that review done in this case?  
(Blunden) Yes. I mean, NSPI has always focused on reducing its costs to levels -- to  
the most appropriate level possible. I believe we continue to do that. I think our  
OM&G report filed a couple of years ago and updated for the last rate application  
would demonstrate that. There had been a number of individual expense items that  
seemed to be occurring at this point in time, whether it's the regulatory climate,  
whether it's through customer expectations on storm response, or changing pension  
expense, but from our perspective the costs are reasonable and reflective of what's  
needed to run the business in 2006.  
Q.  
But the result is that after you've done this review your requested rate increase still  
averages 13 percent. So my question was how did you go about reviewing the -- and  
let me just back up a bit. When I mentioned operating expenses, the only operating  
expense we're talking about is what's in OM&G, is that correct? There's no other  
operating expenses per se. I'm not talking about capital expenditures, I'm talking  
about operating expenses.  
A.  
(Blunden) Yes, I understood you to mean OM&G expenses, correct.  
Q.  
Yes. So in view of that, then, how did you go about reviewing the OM&G expenses to  
see whether or not there could be additional savings achieved in order to reduce a  
requested rate increase? OM&G has increased by, I think, somewheres around 29  
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million dollars, which is about a 15 percent increase in this year. So I understand that  
some are higher by necessity, but the question is how did you go about reviewing the  
different categories of operating expenses to see whether or not you could make  
cuts or other savings?  
A.  
(Blunden) Certainly as part of our annual business planning process and as part of  
this rate application we always look at our operating expenses and determine, you  
know, certainly a starting point from baseline perspective whether we think they're  
reasonable, and that certainly has not changed. When we look at, in particular, how  
difficult this year has been from a financial perspective, our baseline OM&G costs  
are where they're at. The increases that are before the Board at this hearing are --  
and are very specific, they're specifically related to pension expense. An example  
would be as we change the methodology coming up with the discount rate last year,  
which has had the effect of reducing pension expense by 2.7 million dollars as an  
example, or they're tied to initiatives like demand side management or storm  
response. So from a baseline perspective despite load growth -- and our operating  
expenses may be characterized slightly different than they would be in some  
companies. Our operating expenses include the variable labour at our plants and our  
linesmen and those kinds of things. You know, load is up, customers are up, inflation  
is up and the fact that we've been able to keep our baseline OM&G flat over quite a  
number of years I think speaks volumes to how well we manage our baseline costs.  
Q.  
A.  
But I think what I was trying to get at is whether or not you had -- you went through  
an internal exercise to look at these expenses and say -- recognizing that from a  
benchmarking perspective they may be in line with other utilities, but that really  
wasn't my question. My question was did you have an internal exercise to go through  
these expense items line by line, item by item, to see whether or not you could, by  
reorganizing or restructuring some of your internal departments, whether or not you  
could achieve additional savings in view of the significant rate increase that you're  
requesting the Board to approve?  
(Blunden) And I think the only thing I can probably respond to that is it's not -- we  
didn't undertake a different exercise but it's kind of part of how we do business on a  
daily basis. Certainly, at least quarterly, if not monthly, we would meet or a couple of  
us would meet with some of the senior managers in all the operating units and  
review their year-to-date spending and where there's possibilities for cuts. Anything  
that we believe is possible to do we have reflected in our 2006 rate application in  
terms of cost reductions.  
Q.  
A.  
I'm not sure that that completely answered my question. Was there an exercise or an  
activity, a specific activity, internal, to look at these expenditures to see where cuts  
could be made from -- obviously you can't cut if service is going to be impaired, that's  
a given, but in any entity there are always some areas where it's a worthwhile  
exercise to look at these things and take a hard line on the expenditures to see  
whether or not -- what would happen if you did eliminate some or reduce some or  
make certain restructuring in your operation. Was that type of an exercise carried  
out?  
(Blunden) It has been over a number of years, and what I mean by that is that  
approach has been taken to all of our OM&G costs over the last number of years,  
which is why we've been able to maintain them to where they're at. To the extent of  
where future opportunities, we have not identified -- any opportunities that we have  
identified have been reflected in this application and we have not been able to  
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identify any additional opportunities that wouldn't have a significant impact on  
service.  
Q.  
A.  
Was anything done in connection with this rate application that was different than  
what you've been doing every year for the last few years? And, to be fair, I recognize  
that OM&G has been discussed extensively in the past, but this is somewhat of a  
different situation. And so was anything done differently this time than what you do  
every year?  
(Blunden) No. Again we believe the approach we have taken is an appropriate one  
and we maintain that approach.  
(Transcript, November 30, 2005, pp. 2725 - 2730)  
[432] With respect to PWC=s suggestion that NSPI should provide multi-year forecasts of  
projected OM&G spending levels, Mr. Blunden questioned the merit of such an exercise:  
A.  
(Blunden) We do not do detailed OM&G forecasts multi-years out, that's correct.  
Q.  
(Deveau) In terms of PriceWaterhouseCoopers, however, they believe that you  
should, shouldn't you, because they say at page -- if you refer to page 16, starting at  
line 4:  
"We believe that it would be prudent for NSPI to provide in support of future  
rate cases detailed five-year forecasts of OM&G costs. The review of such  
forecasts, we believe, would increase overall transparency and allow the  
Board to see the quantification of certain forward-looking plans and  
programs including..."  
And just -- obviously DSM is in there and regulatory costs are in there as well, isn't  
that right?  
A.  
(Blunden) Yes.  
Q.  
And just further on that point -- and this is arising, I think, from questions that Mr.  
Merrick and Mr. Mahody asked you in terms of cost-efficiency programs Bwouldn't  
such projections into the future for OM&G costs -- wouldn't they provide a valuable  
tool for assessing cost-efficiency in the management of NSPI in terms of OM&G  
costs? And I suppose my final question is, do you agree with PriceWaterhouse's  
recommendation that such projections should go five years in advance? Sorry, five  
years into the future.  
A.  
(Blunden) If I could direct you to our rebuttal evidence, on page 84, we -- our  
intention was to respond to the suggestions made by PriceWaterhouseCoopers. In  
isolation we believe three-year forecasts or multi-year forecasts of OM&G by  
themselves is not overly relevant because -- and there's a whole list of things that  
influence that, whether it's load growth, changes in the regulatory environment,  
pension expense, those kinds of things. For any of our planning purposes, unless we  
know of the specific change in an area of our OM&G, we have found over time that  
increasing it by inflation for management purposes is a reasonable proxy only  
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because a number of the other line items have a much greater likelihood of changing  
more materially, for example, fuel expense.  
Q.  
A.  
But that's not the case in this year, is it, because this year the increase [for OM&G] is  
quite significant?  
(Blunden) Yes, and some of the increases that we're experiencing -- and whether it  
be increased pension expense because of changing discount rates or incremental  
costs that have been, you know, I guess, the results of storm hearings and those  
kinds of things -- would not have been things that we would have been able to  
forecast three years ago. So, those would be examples of multi-year forecasts in  
OM&G that in isolation wouldn't necessarily be overly relevant.  
Q.  
A.  
So, is what you're saying that you don't believe that three or five-year forecasts are  
helpful at all in assessing expenses into the future?  
(Blunden) I think in areas where you believe there are going to be step changes in  
some of your operating costs I think they can be useful, but they are just forecasts.  
We tend to believe that a more appropriate evaluation of our operating cost structure  
is looking at where we're at today versus where other utilities are, what our trend has  
been, so focusing more on actual results and informal comparisons as opposed to  
future forecasting.  
(Transcript, November 30, 2005, pp. 2708-2711)  
[433] Following its review of the evidence in this hearing, the Board continues to be concerned  
about the magnitude of the increase sought by NSPI for OM&G expenses, particularly since it  
accompanies NSPI=s request for a very significant rate increase. In its application, NSPI is seeking  
an increase of $27.8 million in OM&G costs for the 2006 test year. This represents a 15.3% increase  
over the 2005 Compliance Filing. Moreover, OM&G spending is not insignificant, representing  
24.5% of the total projected cost of operations.162  
[434] While the Board accepts NSPI=s evidence that the Company=s management endeavours to  
contain line expense amounts, it is not persuaded that NSPI has taken sufficient steps to critically  
examine its entire operation to determine the most efficient use of its resources. In the opinion of the  
162NSPI Application, Exhibit N-2, Appendix A, Table 2 ($209.8 M of $858.0 M)  
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Board, any large entity should regularly undertake such a review, without reference to, or reliance  
upon, traditional or existing operational groups. Such a review should focus on developing the most  
efficient organizational structure as the Utility moves into the future.  
[435] Accordingly, the Board directs that an operations review be carried out on NSPI=s  
operations. The review shall encompass a detailed examination of NSPI=s organizational structure,  
its level of OM&G expenditures, and any other pertinent areas which may come to light, with a view  
to determining whether cost savings and operational efficiencies can be achieved. NSPI is directed  
to prepare the terms of reference for the operations review and submit them to the Board for  
approval by May 31, 2006. The terms of reference shall also set out the procedures for identifying  
and selecting the firm or person who will perform the operations review.  
[436] PWC has recommended that future rate applications contain detailed five year forecasts of  
OM&G costs. The Board accepts this recommendation and directs NSPI to include detailed five  
year forecasts of OM&G costs in all future rate applications.  
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7.0  
DEMAND SIDE MANAGEMENT  
7.1.1 Overview  
[437] In the 2005 rate decision, the Board directed the Company to initiate a technical conference  
process with respect to a Demand Side Management (ADSM@) plan.  
[267] The Board has considered the helpful information provided on the matter of DSM  
during this proceeding. In the Board=s view, further work and progress with respect to DSM  
is both important and necessary. The Board understands the suggestion that a DSM hearing  
should be held and, indeed, such a hearing may well be ordered in future. At present,  
however, the Board believes it is more appropriate to direct NSPI to initiate a technical  
conference process, with interested parties and stakeholders, to pursue an improved and  
effective DSM program for the Utility.  
(Board Decision, March 31, 2005, para. 267)  
[438] NSPI stated in this application that it is currently engaged in a number of DSM initiatives  
which will reduce long term capacity requirements and environmental emissions. NSPI=s current  
annual expenditures for DSM are approximately $0.5 million and it is proposing to increase this  
amount by $5.0 million annually as outlined in its rebuttal filing.  
7.1.2 Submissions - NSPI  
[439] NSPI=s application outlined the process it followed to prepare its DSM Plan:  
... , the Company invited a cross section of community leaders with an interest in demand  
side management to participate on a committee that will design and organize a special forum  
on energy conservation and efficiency planned for September 2005 in response to the  
Board=s direction.  
The Company will incorporate feedback about past technical conferences and its November  
2004 Customer Energy Forum to ensure that this technical conference process sets in motion  
an enhanced program of demand side management that meets the expectations of  
customers and other stakeholders.  
The specific new DSM programs to be implemented by NSPI will ultimately be a function of  
the ideas generated in the stakeholder consultations, in conjunction with technical feasibility  
and economics. NSPI will pursue opportunities to improve the economics of DSM programs  
through partnerships with other stakeholders.  
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NSPI=s increased DSM activities will provide tangible benefits to the environment, as well as  
practical means for customers of all classes to save money in the face of rising energy costs,  
particularly important to those in lower income situations.  
As a result of a number of existing DSM initiatives and awareness programs underway during  
2004 and 2005, NSPI estimates a 0.5% reduction in forecast energy requirement for 2006. It  
is NSPI=s view that an additional $5.0 million investment is the minimum required to ensure  
that the ongoing opportunities for DSM, as part of meeting the future energy needs of Nova  
Scotia, are fully optimized, and that the expectations of our customers to help them save  
money and reduce emissions are met.  
(Exhibit N-1, pp. 100-101)  
[440] NSPI, in its Rebuttal Evidence, provided additional information and also included a copy of  
its proposed DSM plan AConservation and Energy Efficiency Plan 2006" (the APlan@).  
[441] NSPI is proposing to spend an additional $5 million in the test year on various initiatives  
included in the Plan. It has stated that if the Plan is approved by the Board the following objectives  
and results can be expected:  
Approval of this plan will advance energy efficiency and conservation in Nova Scotia. It will:  
$
$
$
reduce electricity usage and save our customers money  
reduce greenhouse gas emissions and help the environment  
help build a conservation and energy efficiency culture in Nova Scotia, led by our  
young people and our schools  
$
$
bring Nova Scotia Power together with community based partners in the province,  
leveraging the efforts and investments of all in its worthwhile pursuit  
meet customer expectations that Nova Scotia Power do more to advance energy  
efficiency and conservation  
Specific Results to be achieved for 2007 include:  
$
$
72GWh reduction in annual electricity usage  
Approximately $7.7 million in annual savings to customers from this reduction in  
usage  
$
$
16 MW reduction in peak electricity demand  
50 thousand tonne reduction of green house gases  
(Exhibit N-153, Appendix A, p. 2)  
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[442] NSPI developed the Plan by identifying possible options, engaging a team of industry leaders  
to identify opportunities with the greatest potential, hosting customer forums, ultimately finalizing  
each element of the Plan. The Plan includes programs for residential, commercial and industrial  
customers. The Plan has three kinds of programs: programs led by NSPI; programs led by others;  
and future program development. Each of these programs has one or more of the following four  
elements: lighting; price awareness; workshops; and youth education. In addition to a cost benefit  
analysis, the Plan also provides a cost breakdown for each element of all programs.  
[443] A detailed table of the proposed Plan is contained in Appendix D.  
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[444] The Plan includes the expected load reduction for each element of the Plan, and also provides  
a sensitivity analysis for variations in the expected load reductions for each element of the program.  
7.1.3 Submissions - Intervenors and Dr. John Stutz  
[445] Board Counsel=s expert, Dr. John Stutz, along with a number of intervenors, were very  
critical of the Plan. NSPI compiled these criticisms as follows:  
1.  
2.  
3.  
NSPI has not provided enough detail to allow UARB approval (Brockway, PWC,  
Stutz, Rosenberg, Drazen).  
NSPI=s approach to developing its Conservation and Energy Efficiency Plan is not  
consistent with good practice, and cannot result in a good plan (Brockway).  
The consideration of NSPI=s DSM plan should be conducted in a separate hearing  
process (Brockway, PWC, Stutz).  
4.  
5.  
NSPI should implement inverted rates to promote energy conservation (Hughes).  
NSPI should direct the entire $5 million investment to give away as many Compact  
Fluorescent Lamps (CFLs) as possible to NSPI=s customers (Hughes).  
6.  
7.  
The Board should disallow the 0.5% forecasted effect of DSM on 2006 load  
(Drazen).  
NSPI has not provided a forecast of DSM spending beyond 2006, so it could decide  
not to spend any additional money in 2007, after obtaining the funding as part of  
rates (Rosenberg).  
8.  
NSPI=s proposal harms those customers who do not participate in the programs  
(Rosenberg, Drazen).  
9.  
NSPI should allocate no share of the DSM investment to SEB.  
10.  
NSPI could make money by Aselling@DSM to customers in return for their first year  
savings, which are assumed to be twice the DSM investment made by NSPI. This  
profit margin of 100% would be used to lower rates.  
(Exhibit N-153, pp. 87-88)  
[446] Avon believes that the Plan is premature and questions the process followed by the  
Company:  
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176.  
At its most basic level, we respectfully submit that the request for $5 million for DSM  
spending is premature in the absence of a well thought out plan which sets priorities based  
on long term planning and short term goals and does a cost-benefit analysis of the options.  
NSPI itself in a presentation made to the Energy Research and Development Forum in  
Antigonish in May of 2004 had stated that the initial step in the establishment of a plan should  
be consideration of load objectives and development of programs to meet these objectives as  
measured against an objective analysis. Instead, NSPI=s initial step was the establishment  
of a $5 million budget.  
(Avon, Redacted Closing Submission, p. 37)  
[447] Avon also questioned whether the Plan benefits the customers:  
178.  
For the $5 million expense, NSPI estimates a reduction of forecast load in the range  
of 72 GWh. The cost for the DSM however is higher than the avoided fuel cost savings. For  
expenditures of $5 million in 2006, ratepayers can look forward to reduced revenues greater  
than the avoided generation cost of $1.83 million which will further be required to be made up  
in rates.  
(Avon, Redacted Closing Submission, p. 38)  
[448] Avon expressed reservations about the success of the Plan, especially with respect to its  
emphasis on residential customers:  
183.  
75% of the $5 million in the DSM plan is in the residential sector and about 85% of  
savings are to come from the residential sector. This is stated to be largely due to the use of  
compact fluorescent lighting (CFL=s) and a grade 5 education program. In cross-  
examination, Mr. Outhouse challenged the panel with an extract from the Environmental  
Commissioner of Ontario Annual Report indicating that the commercial and institutional  
sectors could offer substantial savings. NSPI was unable to point to any hard analysis that  
showed there were not similar opportunities in these sectors in Nova Scotia.  
(Avon, Redacted Closing Submission, p. 39)  
[449] The Consumer Advocate submits that the proposed expenditures are not based on a need  
assessment analysis. He questions the appropriateness of the Plan=s elements, their costs and  
effectiveness:  
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34.  
The method of developing the program gives little confidence that it is an appropriate  
expenditure of ratepayers money. The $5 million was not based on any analysis of what was  
needed to implement specific programs. Rather NSPI chose the amount and then looked for  
ways to spend it. The amount was arrived at by May, 2005 prior to any effort being made to  
develop the program itself. It was primarily motivated by an estimate of what NSPI  
understood to be the typical range of amounts expended by other utilities on DSM programs  
in relation to their total expenditures. The $5 million was allocated to the various rate classes  
prior to the development of the program. Having identified the amount to be spent, it was  
only in July that the company began the process of seeking input for the purposes of  
identifying elements of the program. After the elements of the program were identified it was  
either intentional or fortuitous that the original allocation of costs to the rate classifications  
were as originally allocated.  
(CA, Redacted Closing Submission, p. 9)  
[450] The Consumer Advocate also expressed concern about the possibility of a conflict of interest  
on the part of the Company in its implementation of the Plan. He stated that:  
46.  
One of the issues to be addressed by the DSM program is whether it should be  
administered by NSPI or by an independent entity. There are a [sic] areas of concern when a  
utility itself administers a DSM program.  
_
There is a conflict of interest. The basic function and purpose of a utility is to sell as  
much energy as possible. The objective of a DSM program is to reduce the sale of  
energy. The conflict is illustrated by the fact that the majority of the DSM funding  
which NSPI has proposed would be administered by the sales and marketing  
department (see Application page 97).  
_
Projecting large energy reductions as a result of a DSM program results in higher  
rates that then turn into bottom line profits if the reductions are less than projected.  
_
_
There may be a temptation to use DSM funding for essentially a PR program.  
There may be a temptation to use DSM funding to cover existing administrative and  
staffing costs.  
47.  
For those reasons, one of the issues to be addressed is whether it would be practical  
for an independent entity to administer a DSM program in this jurisdiction.  
48. For similar reasoning, we recommend that the choice of the consultant be either at  
the discretion of, or approved by, the Board. Input as to the selection of the consultant should  
be available not only to NSPI but to any interested stakeholders.  
(CA, Redacted Closing Submission, pp. 12-13)  
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[451] The CME is of the view that the Plan is incomplete, and only a limited amount of funds  
should be approved to complete the Plan:  
23.  
It is the view of the CME that only a limited amount of money be allocated for the test  
year for the design of a DSM program. It is also the view of the CME that there are  
likely many benefits that accrue to NSPI in the short and longer term and that it could  
be funded wholly by NSPI and if not, should be amortized over an appropriate period  
of time.  
(CME, Redacted Closing Submission, p. 12)  
[452] Ms. Brockway questioned the expertise of the Company to prepare the Plan:  
Q.  
So, can a utility design an effective DSM program without drawing on individuals with  
specific utility DSM expertise?  
A.  
In my opinion, a utility cannot design effective DSM programs without drawing on  
individuals with professional DSM design expertise. Utility DSM efforts are  
specialized programs. DSM program designers need considerable experience and  
expertise, whether they are on the staff of the utility, or their expertise is acquired  
from outside the utility. I am not saying that a utility should draw its program designs  
only from the conventionally-accepted set of approaches to DSM that are in  
widespread use among utilities. After all, I am chair of a non-profit devoted to  
disseminating information on an innovative approach that is not yet in widespread  
use. However, I am saying that a utility (and its regulator) cannot hope to  
understand the problem it is trying to solve with DSM programs, and cannot  
understand the pros and cons of available DSM options, without drawing on  
expertise regarding the myriad DSM efforts that have been funded by utilities in the  
last 20 years. [Indeed, a detailed awareness of the reasons for program failure is as  
useful as awareness of what programs are standard practice.]  
(Exhibit N-87, pp. 20-21)  
...  
Q.  
Are you saying the public is not qualified to draft a DSM program?  
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A.  
I am saying that drafting a utility DSM Program is as technical an exercise, and  
requires as much expertise and professional experience, as drafting a plan for  
installation of a substation, or preparing a load forecast, or designing rates. The  
expertise is different, but it is needed nonetheless. The devil is in the details, many  
things that appear intuitively obviously turn out not to work as one might think, and it  
is all too easy to reinvent a poorly-functioning DSM Awheel@rather than achieve a  
program design that could work according to its specifications. Reasonable DSM  
experts can and do disagree on how best to achieve with DSM goals, but at the very  
least they can call out these issues to the attention of the Board for its ultimate  
determination.  
(Exhibit N-87, p. 23)  
[453] Ms. Brockway outlined some key components which she recommends be explored before the  
Plan can be evaluated:  
Q.  
Please describe some necessary elements of a DSM plan that the Company has not  
yet developed.  
A.  
Before a DSM program can be evaluated, certain key components need to be  
developed. Without limitation, these include (a) determination of the cost-  
effectiveness standard for measures and programs [which in turn is guided by a clear  
understanding of the legitimate purposes of a utility DSM effort], (b) the target  
markets for DSM offerings [e.g. should programs be designed to provide benefits to  
all customers, even if it is less cost-effective to serve DSM needs of some  
customers?], (c) budgets for each class and for each program, informed by the  
overall goals of the initiative and by the cost-effectiveness results for various  
measures and programs; (d) allocation of costs to classes and subclasses based on  
principled allocation factors; and (e) cost-effectiveness screening of all measures  
and programs against the cost-effectiveness test or test that is chosen for the  
initiative, the program or the measure, as the case may be. It is also important to  
specify how the program will be evaluated, so that necessary data gathering can  
commence with program roll-out.  
(Exhibit N-87, pp. 18-19)  
[454] The Ecology Action Centre argues that the Company placed too much focus on lighting in  
the Plan, leaving other important areas under-funded and under- recognized:  
The EAC supports NSPI in their dedication of five million dollars towards DSM in the  
upcoming year, and the commitment that NSPI senior staff has displayed to working with  
other organizations to build a DSM plan which they believe will maximize their investment.  
The Ecology Action Centre continues to have reservations about the current heavy focus on  
lighting in NSPI=s DSM plan. NSPI=s assertion that breakthroughs in lighting technology and  
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their associated costs have occurred that would allow for energy savings with a small  
investment is valid. The heavy focus on lighting, however, leaves other important areas  
under-funded and under-recognized, and risks ignoring more substantial energy efficiency  
improvements.  
The EAC maintains that Nova Scotians would benefit more, in the long term, from additional  
DSM initiatives involving retrofits and increased awareness and efficiency in the areas of  
space and water heating.  
At present, NSPI=s Conservation and Energy Efficiency Plan is the major method by which  
changes to Nova Scotian power use may be targeted. These changes are required to  
support our commitments to Kyoto and to the New England Governors/Eastern Canadian  
Premiers Climate Change Action Plan. As these commitments have been made on behalf of  
Nova Scotians, they deserve assurance that the commitments will be met. This program  
deserves the continued input of Nova Scotians and oversight on their behalf.  
The EAC continues to call for a demand side management hearing early in the year 2006 as  
an ideal opportunity for government and NSPI to work collaboratively on DSM and pollution  
reduction initiatives.  
(EAC, Redacted Closing Submission, pp. 5-6)  
[455] The Electrical Consumers Alliance of Nova Scotia was in full support of the Plan at the start  
of the hearing process. However, based on the evidence provided during the hearing, ECANS  
tempered that support:  
However, upon reflecting, we agree that a deferral is probably in the best interests of all  
parties - ratepayers and shareholder.  
We are convinced NSPI has the full complement of talent to successfully implement a DSM  
program. On that, there is no doubt. What is at question is the level and degree to which the  
contents of this particular DSM concept have been debated in the public forum. It also has  
not been measured against >tried and proven=DSM programs in other jurisdictions.  
So, taking a small step sideways, we now believe the best value for DSM dollars can be  
obtained by:  
>
>
Locking the $5 million into rates for 2007.  
Including $500,000 in rates for the year 2006 to allow NSPI to move forward  
as explained below.  
>
>
>
Engaging an external DSM consultant to advise all parties on DSM  
components that are tailored for NSPI ratepayers.  
Hold technical conferences (both before and after) the consultant prepares  
his/her report.  
Including DSM as a formal portion of the hearing to set rates for 2007.  
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In this way, there can be more certainty that we will save as much as we spend. It is  
imperative we get DSM right.  
(ECANS, Redacted Closing Submission, pp. 13-14)  
[456] Halifax Regional Municipality supports DSM, but does not agree with the Plan as proposed  
by NSPI:  
b)  
Comments on the Energy Conservation Plan  
The plan addresses only a start to energy efficiency and conservation. Unfortunately, the  
plan does not address any load shifting initiatives. A DSM plan needs to address both  
aspects of DSM, energy conservation and load shifting as recognized by Chuck Faulkner in  
Exhibit N-162. A DSM plan also needs to have a long term vision to be able to set short term  
goals. As has been pointed out, a DSM plan should have measurable results and a feedback  
and reporting mechanism to both consumers and the UARB. HRM believes that there is a  
shared responsibility between NSPI and its customers to implement an effective DSM Plan;  
however it is the UARB=s responsibility to create the guidelines and incentives to enable  
DSM to happen effectively. As noted by the Consumer Advocate, NSPI noted that there were  
aspects of the program that had not yet been developed.  
Due to the importance of DSM, the setting of DSM targets, budgets, timelines and the means  
of measuring DSM success need to be included in any DSM plan. Additional economic  
incentives that create the climate for a sustainable DSM Plan incorporating measurable  
energy efficiency and load shifting goals should also be considered for inclusion. As an  
example, a higher ROE on effective DSM expenditures might be considered.  
(HRM, Redacted Closing Submission, p. 12)  
[457] HRM indicated that it supports the proposal put forward by the Consumer Advocate and has  
also suggested that the following items be included in the Plan:  
NSPI direct some resources to provide electronic data interchange (EDI) with its largest  
customers.  
NSPI increase the capability of its Smart Meter program to increase the timeframe for  
available data.  
If the DSM Program is to be administered by NSPI, consideration should be given to it being  
administered by the Generation group and not by Marketing & Sales.  
(HRM, Redacted Closing Submission, p. 16)  
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[458] Dr. Larry Hughes, a professor at Dalhousie University, filed Direct Evidence and a Closing  
Submission. He recommended against Board approval of the Plan. It is his opinion that the most  
cost effective way to use the funds is to initiate a program of demand reduction, EnerGuide for house  
renovations/new construction, and promotion of conservation and energy efficiency. He suggested  
that the following recommendations could form an alternative DSM program:  
$
More of the funds should be devoted to demand reduction: this means a CFL  
programme that targets those on low-and fixed-income first, replacing all bulbs  
(those involved in last year=s Keep the Heat programme are apparently pleased with  
them). If $4 million were devoted to this at $4/bulb, 1 million bulbs could be  
purchased and installed.  
$
$
The EnerGuide for Houses programme element should be increased to $520,000 (to  
include audit costs) and targeted at those on low-and fixed-income who use electric  
heating.  
The remaining $480,000 should be used to promote conservation and energy  
efficiency; for example, through advertising campaigns encouraging customers to  
use less electricity during peak periods.  
(Dr. Hughes, Redacted Closing Submission, p. 9)  
[459] The Province argued that the Plan provides sufficient details and was developed by input  
from stakeholders, including feedback from a consumer forum held by NSPI. It is the Province=s  
view that the Plan should be approved with the following modifications:  
56.  
Dr. Stutz and Ms. Brockway have suggested that some formal DSM consultant  
should be involved at the outset. The Province supports the stakeholder driven  
process that NSPI has undertaken at this stage. The Province believes that,  
following the initial implementation of NSPI=s DSM plan, an independent  
assessment of the first year=s results should be undertaken by a consultant  
specifically retained for that purpose, to ensure that the DSM program is on track.  
(Province, Redacted Closing Submission, p. 24)  
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[460] The Province also submits that, in case the Board decides not to approve the Plan, it supports  
partial approval of funds to retain an outside consultant to complete the Plan.163  
[461] The Nova Scotia NDP Caucus made a presentation to the Board at the evening public  
session, and submitted a petition signed by approximately 32,563 citizens of Nova Scotia. The  
petition requested that there be no increase in electricity rates until NSPI and the Province assist the  
customers of NSPI to save at least 15% on their electricity bill.  
[462] The NDP Caucus has indicated that it would like to see further scrutiny of the Plan in a  
separate hearing in 2006:  
For the NDP, one of the central issues regarding DSM are the intentions of the Board  
respecting further scrutiny of the issue in detail, as a follow up to the 1992-93 set of hearings  
and the Board=s 1996 discussion of Integrated Resource Planning on DSM in its rates=  
decision. Our request is that the Board move to convene a separate set of DSM hearings at  
an early date, certainly some time in 2006.  
(NDP, Redacted Closing Submission, p. 9)  
[463] SEB, in its Closing Submission, expressed concern about the timing of the submission of the  
Plan, stating that the Plan did not provide sufficient time to review and cross-examine the Company.  
SEB also questioned the allocation of DSM costs to below-the-line customers, especially ELIIR  
customers. SEB=s recommendation is that a separate and more focused DSM proceeding be held  
before the Board approves the Plan.  
163Province, Redacted Closing Submission, para. 57  
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[464] The Nova Scotia Liberal Caucus, in its Closing Submission, noted that NSPI needs to do  
more in its Plan to provide real reductions in energy use. It is their view that consultation with  
professionals in this field is required to achieve the desired results.  
[465] Dr. Stutz described his opposition to the Plan as follows:  
... NSPI has included five million in required revenues to fund its conservation and energy  
efficiency plan for 2006. The plan was filed on November 7 as part of the company's rebuttal.  
The plan is 54 pages in length. It contains large amounts of data, and the results of technical  
analyses. Work papers explaining and supporting the plan have not been filed. There has  
been no opportunity for parties to submit information requests on the plan or to address it in  
their evidence. In 2004 and 2005, NSPI spent about five hundred and fifty thousand dollars  
($550,000) on energy efficiency and conservation. The 2006 plan calls for a roughly tenfold  
increase. A thorough review is appropriate. This can best be accomplished through a  
separate hearing to be held early in 2006. Until such a hearing is held, there is no reasonable  
basis for approving funding for the 2006 plan. Funding for energy efficiency and conservation  
at the level of 2004/2005, that is, five hundred and fifty thousand dollars ($550,000), should  
be approved now to permit work on conservation and energy efficiency to continue. In its  
decision and order in the hearing just mentioned, that is, the hearing to be held in early 2006,  
the Board could authorize additional spending in 2006 on the 2006 plan, subject to deferred  
cost recovery if that proves appropriate.  
(Transcript, December 2, 2005, pp. 3511-3512)  
7.1.4 Findings  
[466] The Board has considered all the evidence provided during the hearing including the  
comments expressed at the public sessions on November 23-24, 2005, and final submissions.  
[467] The Board has reviewed the DSM Plan submitted by NSPI and commends its effort in  
preparing the Plan, including conducting deliberative polling, forming a stakeholders committee and  
seeking customer input at the Company=s customer forum. All intervenors and consultants generally  
agree that DSM is important and that it ought to be pursued. However, most of them have raised  
issues with the lack of analysis in the Plan and its late filing. The Plan was filed with the Board as  
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part of NSPI=s Rebuttal Evidence on November 8, 2005, and proposes an increase of $5 million  
annually, a tenfold increase over the current level of spending on DSM.  
[468] The Board understands that the Company=s request is for the approval of an additional $5  
million annually, but it is not seeking approval of the details of the Plan as submitted. Board  
Counsel clarified this issue during cross-examination of NSPI=s witnesses:  
Q.  
Just to follow up on that point of clarification by Mr. Gallant that NSPI is looking for  
approval of the budget but not approval of the plan, what control does the Board  
have over the spending of that $5 million dollars if the plan elements are not vetted  
and approved?  
A.  
(Tedesco) For this hearing we've put forth our proposal. Upon listening to  
stakeholders and participants in this hearing, the Board can clearly decide what it  
thinks is in the best interest of our customers and how best to invest that money.  
Q.  
A.  
But you're not looking for approval of any specific plan elements?  
(Tedesco) The plan represents our recommendation, and as was said a moment ago,  
we're really looking for input from customers. We sought to put forward a specific plan  
that identified how we might invest the money based on what we heard or what we  
thought we heard from customers. We also recognize the Board may have other  
interests and perspectives that need to be considered, and I would view it as really no  
different than any other investment of this magnitude that the company might  
undertake.  
THE CHAIR  
Excuse me, Mr. Tedesco. How does that differ from if the Board requests -- if NSPI  
requests the Board to approve a capital expenditure, how do you see the difference  
between that and this scenario?  
MR. TEDESCO  
I think the analogy is quite similar, that I would view this in a similar sort of way, that  
it's a significant amount of money, the company in the case of a capital expenditure  
would put forward a plan, the Board may have questions about it, the plan may be  
modified as a result of information that is discussed and provided to the Board, and  
we understand that and I would look at that as the normal course of events.  
THE CHAIR  
But the Board would normally approve the capital expenditure after reviewing the  
economic scenarios, et cetera.  
MR. TEDESCO  
That's right.  
THE CHAIR  
But you're not asking in this case the Board to approve this particular plan?  
MR. TEDESCO  
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We're not asking that this specific plan be approved, we're simply seeking to  
demonstrate that we've put forward -- now we have given some thought to how we  
would propose investing this money. We also recognize that others may have different  
opinions.  
(Transcript, November 16, 2005, pp. 517 - 519)  
[469] A number of intervenors have argued that the Plan was submitted too late in the process, and  
they did not have sufficient time to review and prepare their evidence in relation to it. They assert  
that the Plan contains technical information and required input from their experts, who did not have  
sufficient time due to the Plan=s late filing.  
[470] The Province, however, supports the Plan on the basis that the Company has followed a  
stakeholder driven process and that the Plan provides sufficient details for approval by the Board.  
The Province is recommending approval along with an independent review by an outside firm after  
the first year of implementation to confirm whether the Plan is on track. The Province has also stated  
in its Closing Submission that, in the event the Plan is not approved, the Board approve funds to  
retain an outside consultant to finalize the Plan.  
[471] Ms. Brockway opposes the Plan, but recommends approval of $550,000 to retain an outside  
consultant to finalize the Plan. It is also her view that there are additional opportunities which need  
to be explored, and which could be more effective than those proposed in the Plan.  
[472] Dr. Stutz testified that the Board should approve additional funds in the amount of $550,000.  
When cross-examined by Mr. Connors, he explained that this amount would keep A... the design and  
development process moving, and it=s out of that that I would expect the consultant and other  
activities to be funded.@164  
164Transcript, December 2, 2005, p. 3566  
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[473] The Board, having considered all the evidence, agrees that approval of the Plan, as submitted  
by NSPI, is premature at this time. Clearly, the Plan needs additional design work and resources. It  
is important that DSM move forward, but not without regard to its cost effectiveness. NSPI  
customers expect that any DSM program will be carefully designed to ensure its maximum impact,  
and that it is effectively implemented. The Board concurs with Ms. Brockway and Dr. Stutz that a  
DSM program requires expert input. Accordingly, the Board approves $550,000 in additional funds  
(and not the $5 million requested by NSPI) to retain an outside consultant and to complete the Plan=s  
design and development.  
[474] NSPI is directed to prepare the terms of reference for the consultant and submit them to the  
Board for approval no later than April 15, 2006. The terms of reference shall contain the procedures  
for identifying and selecting the consultant who will assist NSPI in the finalization of the DSM Plan.  
The process of retaining and selecting the consultant will be monitored by the Board.  
[475] A number of intervenors have raised the issue as to whether NSPI should be implementing the  
Plan. This is based on their view that the Company may be in a conflict of interest position since its  
business involves the generation and selling of electricity, and pursuing its shareholder interests. The  
objectives of DSM are demand reduction and energy efficiency, which may conflict with the  
Company=s mandate (i.e., sell more electricity). The Board does not have a view on this issue at the  
present time and directs that it be part of the mandate of the outside consultant, and that appropriate  
recommendations be included in that consultant=s report.  
[476] The Board has considered the suggestion from intervenors that a separate hearing be held on  
DSM in 2006. NSPI, however, has stated that enough input has been received from its customers and  
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stakeholders with respect to the types of programs they desire, and their anticipated impact. The  
Board agrees that insufficient time was afforded to intervenors to fully review and evaluate the Plan.  
In addition, given the resources and time required to allow a fair review, a separate hearing on DSM  
is appropriate. The Board orders that a separate hearing on DSM be held in the second half of 2006.  
[477] The Board understands that to start the hearing process, the Plan needs to be finalized. The  
Board orders that NSPI complete the Plan and file it with the Board no later than June 30, 2006,  
utilizing the assistance of the Board approved consultant.  
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8.0  
DEPRECIATION  
8.1.1 Submissions - NSPI  
[478] NSPI, in its application, forecasts depreciation expenses of $128.8 million for the 2006 test  
year. This increase is explained by the Company as follows:  
Depreciation expense has increased by $9.0 million to $128.8 million between 2005C and  
2006. The increase principally results from:  
$
$
The continued phase in of revised depreciation rates previously approved by  
the Board. The 2006 test year revenue requirement is calculated based on  
the second year of the four year phase-in of depreciation rates approved by  
the Board in its Decision dated November 21, 2003 in NSUARB-NSPI-P-879.  
Capital additions approved by the Board since December 31, 2004.  
(Exhibit N-1, p. 106)  
[479] The proposed depreciation expense also includes year two of the four year phase-in of new  
depreciation rates which is estimated at $6.6 million.  
The UARB approved the Settlement Agreement (Decision dated November 21, 2003, and  
Order dated December 23, 2003, in NSUARB-NSPI-P-879) and ordered an increase in  
depreciation rates for NSPI's depreciable property. As unanimously agreed by all parties, the  
Board directed that the increase in depreciation rates would be phased in over four years in  
equal instalments commencing January 1, 2004. In its decision in the 2005 Rate Application,  
the UARB deferred the phase-in by an additional year. This reduced the 2005 revenue  
requirement by $6.0 million.  
(ExhibitN-1, p. 106)  
8.1.2 Submissions - Intervenors  
[480] The Municipal Electric Utilities of Nova Scotia Co-operative, the only intervenor to express a  
view on this issue, is of the opinion that the postponement of the second year of the four year  
depreciation rates phase-in is more appropriate this year than last year, given the proposed increase in  
rates:  
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If this was appropriate in a 12.4% increase world (NSPI=s request for 2005 rates) surely it is  
even more appropriate for the 2006 proposal of 14.7%. Depending on future rate increase  
requirements for 2007 and 2008, how this phase-in is to be finally accomplished should be  
reviewed once these are known. Delaying the year 2 phase-in again will reduce the additional  
revenue requirement by some $6.6 million (NSPI Direct Evidence Pg. 107 line 3).  
(MEUNSC, Redacted Closing Submission, p. 4)  
8.1.3 Findings  
[481] In the 2005 rate decision, the Board deferred, for one year, the second year of the four year  
phase-in of the increases in depreciation rates. The deferral was based on the proposed increase in  
rates and potential rate shock to customers.  
[482] In the present application, the Company is proposing an average rate increase of  
approximately 13% (modified from 14.79% after the natural gas settlement). In the 2005 rate case,  
the proposed average rate increase was 12.4%. The Board was concerned about the size of proposed  
increases and rate shock impact on customers. The Board is faced with a similar dilemma this year.  
[483] NSPI, in its closing submission, argues that currently there is a shortfall of about $35 million  
in depreciation expenses, and that any further postponement will add additional expense to the  
customers:  
During its March 31, 2005 decision, the UARB delayed the phase-in by one year and some  
intervenors have suggested through their questions in this rate proceeding that an additional  
deferral may be appropriate. Based on the most recent depreciation study, annual  
depreciation expense is at least $35 million less than it should be. As the UARB believes  
more timely depreciation studies should be carried out (and were in fact carried out), then it  
should be prepared to accept the increases in depreciation expense that were determined.  
Otherwise the exercise adds additional expenses without any actionable response.  
Appropriate recovery of capital expense is not only essential from a cash flow perspective but  
also important component in raising capital to finance the significant capital requirements that  
NSPI will face over the balance of the decade.  
(NSPI, Redacted Closing Argument, p. 84)  
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[484] The Board appreciates the concern expressed by the MEUNSC with respect to the proposed  
rate increases and their impact on the customers. The Board, in the 2005 rate decision, deferred the  
second year phase-in of the four year increase in depreciation rates for one year on the understanding  
that the increase would be resumed in the following year. The Board is also mindful of the issue  
raised by NSPI that the new depreciation rates should be in place before major upgrades to the  
generating stations are completed and become part of the Company=s depreciable assets.  
[485] The Board, having considered all the evidence, approves the resumption of the four year  
phase-in of depreciation rates in the 2006 test year.  
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9.0  
RATES  
9.1.1 Overview  
[486] This section deals with the process to determine customer rates based on the  
Board=s approved revenue requirement for NSPI. The revenue requirement approved by  
the Board is lower than that applied for by NSPI, making the resulting rates lower than those  
proposed by the Company. NSPI is directed to incorporate these changes and submit a  
Compliance Filing for the Board=s approval.  
[487] NSPI customers fall into two categories, above-the-line (AATL@) and below-the-line  
(ABTL@) or Annually Adjusted Rates (AAAR@). BTL rates are adjusted annually based on pre-  
defined methods or existing agreements. NSPI normally makes an application to the Board no later  
than November 1 for approval of rates effective January 1 of the new year.  
[488] ATL rates, on the other hand, are only changed by the Board upon application by the  
Company, and after a full public hearing. Otherwise, they remain the same indefinitely.  
[489] The rate changes for all above-the-line (ATL) rates are to be effective March 10, 2006, and  
the rate changes for all the below-the-line rates are to be effective January 1, 2006.  
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10.0 ANNUALLY ADJUSTED RATES/BELOW-THE-LINE RATES  
10.1 Overview  
[490] NSPI submitted its proposed 2006 AARs for approval on August 5, 2005, earlier than the  
normal November 1 filing date. NSPI described the reason for the earlier filing as:  
... This is in order to provide the opportunity for full review in conjunction with NSPI=s 2006  
Rate Application filed with the Board on June 28, 2005, and to enable the rates to be in effect  
as of January 1, 2006, the normal effective date for AARs.  
(Exhibit N-155, August 5, 2005 letter)  
[491] NSPI currently has the following AARs available for its customers:  
$
$
$
$
$
Mersey System Rate165  
Generation Replacement and Load Following Rate (GRLF)  
One-Part Real Time Pricing Rate (1P-RTP)  
Two-Part Real Time Pricing Rate (2P-RTP)  
Extra Large Industrial Interruptible Rate (ELIIR)  
10.2 Generation Replacement and Load Following Rate  
[492] The Generation Replacement and Load Following Rate (AGRLF@) is designed to provide load  
following and back up service to large customers who own their own generation facilities or  
otherwise qualify for the rate. These are two separate rates: the Generation Replacement Rate is used  
165  
The Mersey System Rate is governed by a separate contract.  
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in case of interruption to the customer=s own generation, and the Load Following Rate is used for  
additional load required by the customer above its own generation capacity.  
10.2.1 Submissions - NSPI  
[493] NSPI proposes a 2006 Load Following Rate of $71.60/MWh compared to the 2005  
rate of $61.60/MWh.166 NSPI states that this rate has been computed using the Strategist  
model to compare a Abase case@with a A25 MW decrement case@as in previous years  
plus a $5/MWh adder. NSPI submits that the reasons for the increase are:  
$
$
increases in heavy fuel oil and natural gas prices  
a higher percentage of the time when the marginal cost is determined by oil or  
gas fired generation  
[494] The Generation Replacement Load rate is to be calculated similar to previous years as a sum  
of a $5/MWh adder and the actual marginal cost for the period of time under which the customer=s  
generation is out of service.  
[495] The GR and LF rates are calculated based on the assumption that there is no export of  
electricity from the system.  
10.2.2 Submissions - Intervenors  
[496] The Board did not receive any submission commenting specifically on the GRLF rate.  
166Exhibit N-155  
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10.2.3 Findings  
[497] The Board has not received any evidence in opposition to NSPI=s proposed GRLF rates and  
they have been calculated as in previous years. Accordingly, the 2006 GRLF rates proposed by NSPI  
are approved by the Board effective January 1, 2006.  
10.3 Real Time Pricing Rate (1P-RTP)  
10.3.1 Submissions - NSPI  
[498] NSPI has three Aone-part@RTP tariffs, one for each of three voltage levels (Extra High  
Voltage, High Voltage and Distribution Voltage) at which RTP customers may be served.167 All  
three tariffs consist of on-peak and off-peak adders set in advance, plus marginal costs as they occur.  
The Board annually approves adjustments to these adders. NSPI states that the proposed adders have  
been calculated using the same methodology as in previous years.  
[499] NSPI provided the following comparison of the proposed 2006 adders to those approved by  
the Board for 2005:  
Comparison of On-Peak Adders  
On-Peak Adder  
(Cents/KWh)  
Off-Peak Adder  
(Cents/KWh)  
167 Exhibit N-155, August 5, 2005 letter, p. 4  
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Proposed  
2006  
Approved  
2005  
Proposed  
2006  
Approved  
2005  
Extra High Voltage  
High Voltage  
Distribution  
6.025  
6.027  
8.359  
5.416  
5.665  
8.171  
0.292  
0.537  
2.149  
0.274  
0.527  
2.102  
[500] In addition, NSPI submits that some clarification is required of the demand level to be used to  
compute the transformer ownership credit in the Extra High Voltage 1P-RTP tariff. The demand  
level is used in applying the transformer ownership credit when 1P-RTP is used along with ELIIR.  
NSPI explains that when maintenance is scheduled by the customer and, if the customer remains at  
the normal peak value for an hour after the maintenance is scheduled to commence, the customer  
receives an unwarranted discount.168  
[501] NSPI is proposing to clarify this by adding a sentence (to be inserted immediately following  
the transformer ownership clause in the Extra High Voltage Time of Use, Real Time Price Tariff) as  
follows:  
When used with the Extra Large Industrial Interruptible Rate (ELIIR), this credit is to be applied  
to 1P-RTP demand levels which occur when the customer=s ELIIR UET is set at normal, and  
not reduced levels as during shutdown periods as permitted under the ELIIR tariff.  
(Exhibit N-155, August 5, 2005 letter, p. 4)  
168Exhibit N-25, UARB IR-16, Attachment 1, p. 27  
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10.3.2 Findings  
[502] There were no intervenor submissions on either the proposed increase in the 1P-RTP adders  
or the proposed amendment to the tariff. The Board approves the adders and the tariff addition  
proposed by NSPI to be effective January 1, 2006.  
10.4. Two Part Real Time Price Rate (2P-RTP)  
[503] The Two Part Real Time Price (2P-RTP) Rate was first approved by the Board in its decision  
dated November 21, 2003, at the request of NSPI and its customers. The rate was to be initially  
available to users of the Extra Large Industrial Interruptible Rate (ELIIR) and later to users of the  
Large Industrial Rate. The Board understands that so far this rate has only been used by ELIIR  
customers.  
10.4.1 Submissions - NSPI  
[504] NSPI, in its application, has indicated that the two ELIIR customers are expected to take load  
under 2P-RTP in 2006. The actual load for 2006 was uncertain, but NSPI has assumed sales of 218  
GWh and estimated revenues of $13 million in calculating rates for 2006. The average net rate for  
2P-RTP is expected to be $60.80/MWh.  
[505] NSPI is also proposing a tariff wording change to address an item identified by NSPI in its  
July 11, 2005 status report to the Board on AARs.169 The issue concerns the amount of economic  
interruption permitted under the ELIIR tariff when a customer uses ELIIR in combination with 2P-  
169Exhibit N-25, UARB IR-16  
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RTP. The amount of economic interruption is determined by the amount of operational Tariff  
Demand (where Tariff Demand is the amount of load subscribed to under the ELIIR tariff) which can  
be at a lower value than the Tariff Demand used to compute the customer=s alternative cost.  
[506] It is NSPI=s position that, by setting a lower Tariff Demand for operational use, the customer  
is able to partially escape the obligation to interrupt but keeps the economic benefit of ELIIR  
pricing.170 This means a loss to NSPI in terms of its ability to avoid some of the high cost  
combustion turbine production and these costs then have to be reflected in the revenue requirement  
for ATL customers. NSPI=s proposed solution is to add back these financial costs into the 2P-RTP  
tariff calculations, thereby charging them to the ELIIR customers.  
[507] NSPI proposes that the following wording be added to the AForecast ELIIR Cost (FEC)@  
section of the 2P-RTP tariff:  
When a customer utilizing the ELIIR in combination with 2P-RTP nominates a UETOP that is  
different than the UETCAC, the difference between these UETs (ie: a modified TD) is to be  
multiplied by the ELIIR economic interruptibility (EI) factor (ie: 0.31 GWh/MW) to determine the  
change in the quantity of EI energy available. This energy quantity is to be multiplied by the  
average CT/High Cost Import unit cost (ie: $/MWh) forecast for the year in which the rate will  
be in effect, to determine the value of the modified EI. This dollar value is then to be  
subtracted from the FEC to determine a ATD Adjusted FEC@for use in determining the CBLbc  
required.  
(Exhibit N-155 and modified by NSPI response to SEB IR-151)  
[508] NSPI states that >net cost=here means the average cost of CT/High Cost Import less the CBL  
base rate for energy.  
170 Exhibit N-25, UARB IR-16, Attachment 1, p. 26  
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251  
[509] NSPI stated in its Rebuttal Evidence that it is not proposing to increase the revenue from 2P-  
RTP, but is merely seeking to achieve the revenue provided by the approved 2P-RTP rate. NSPI  
explained the issue further as follows:  
This issue revolves around Special Condition 3 of the 2P-RTP Tariff. Special Condition 3 was  
added to the tariff at SEB=s request on the morning of the Hearing at which it was reviewed.  
NSPI required that the last sentence of this clause be added as a result of this last-minute  
change to the tariff proposed by SEB. In fact the Hearing was delayed for some time while  
these negotiations were held.  
SEB proposed that the annual quota defining how much energy could be interrupted by NSPI  
for economic reasons should be calculated using the lower UETOP and not the UETCAC . NSPI  
recognized that this would result in a reduced availability of economic interruption while at the  
same time providing a reduced rate to the 2P-RTP customer that would have required a higher  
level of interruptibility. In order to ensure that ATL customers did not pay more as a result of  
this, NSPI requested the inclusion of the last sentence of Special Condition 3 which requires  
that any adjustment of the UETCAC not undermine the value of ELIIR or the three principles  
which underpin 2P-RTP. NSPI has applied the 2P-RTP tariff consistent with Special Condition  
3, requiring 2P-RTP customers to pay for the reduced availability of economic interruptibility in  
exchange for the lower rate they are provided when they reduce the UET that was used to  
develop the original CAC rate.  
NSPI is not proposing to change the 2P-RTP tariff. The Company is seeking to modify the  
wording of the tariff to more clearly state the original intent of special condition 3.  
(Exhibit N-153, pp. 105 -106)  
10.4.2 Submissions - Intervenors  
[510] SEB presented evidence from Dr. Rosenberg on the 2P-RTP rate. Dr. Rosenberg does not  
agree with NSPI=s proposal to change the tariff. In his evidence he states:  
... In the first place the 2P-RTP tariff was meticulously crafted after very extensive negotiations  
and much give and take on both sides, and with the active assistance of Dr. Stutz. The tariff,  
which was agreed to by all parties and approved by the Board, explicitly states that:  
$
$
$
The TDop can be, and indeed must be, different than the TDCAC  
The RTP energy is not subject to economic interruption  
No extra charges are contemplated for these imaginary economic  
interruptions.  
.
In the second place, NSPI=s proposal, if adopted would literally destroy its touted RTP  
program before it has even been allowed to begin.  
(ExhibitN-91, p. 35)  
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252  
[511] Dr. Rosenberg explained his reason for stating that the 2P-RTP program would be destroyed  
by providing a computation showing that by switching from ELIIR/2P-RTP to the Large Industrial  
Interruptible Rate (LIIR), the total charges for a hypothetical customer would be lower under LIIR  
than under ElIIR/2P-RTP with NSPI=s adjustment, plus the customer would not have to incur either  
economic or priority supply interruptions.  
[512] SEB states that:  
NSPI=s position on this matter is, with respect, without foundation. As Dr. Rosenberg makes  
plain in his evidence, both the words of the Tariff and the underlying purpose of the RTP  
program belie the validity of NSPI=s position.  
(SEB Submission on Non-Fuel Matters, p. 27)  
[513] SEB computes (using the NSPI response to SEB IR-151) that, for the 250 MW load of SEB,  
the language change proposed by NSPI would result in the customer paying $5.75 million more  
annually.  
[514] SEB requests that the Board clarify that SEB=s interpretation of the tariff is correct or,  
alternatively, reject NSPI=s proposal and allow the parties to bring the matter before the Board to  
argue the issue in a full and complete manner.  
10.4.3 Findings  
[515] The Board has considered the evidence of NSPI and SEB and understands that the issue is  
intertwined between the 2P-RTP and ELIIR rates. It is also the Board=s understanding that only  
ELIIR customers have signed on for the 2P-RTP rate as of the date of hearing.  
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[516] The Board, for reasons set out later in this decision, has ordered a separate hearing on the  
ELLIR rate or its successor rate, to fully review the impact of the current situation on the Company  
and the ELIIR customers.  
[517] Special Condition 3 of the 2P-RTP tariff currently reads as follows:  
In the event that the ELLIR rate (with or without 1P-RTP) is used to calculate the Customer=s  
Alternative Cost (CAC), the UET rather than the UET (CAC) will define the level of economic  
interruption. The UET will be set at a level which will not undermine the value of ELIIR or the  
three principles which underpin the 2P-RTP.  
[518] Special Condition 3 refers to three principles which underpin the 2P-RTP. The three  
principles are set out in the Board=s decision dated August 1, 2003.171 The Board stated that:  
[143]  
NSPI=s proposed changes to the RTP rates were the subject of discussion  
prior to and during the hearing in an effort to reach a consensus on an acceptable set of RTP  
rates. While a specific rate design was not agreed upon, NSPI, SEB and Dr. Stutz, agreed to  
continue discussions and attempt to develop a rate for presentation to the Board during the  
next general rate case. This agreement was set out in Exhibit N-22 and reads as follows:  
Nova Scotia Power/Bowater Mersey/Stora Enso/Dr. John Stutz  
Statement Regarding RTP  
We have agreed to develop an alternative load  
shifting rate option, the  
principles of which are:  
1.  
2.  
3.  
Under this option the customer who shifts load will never pay more than the  
customer would have paid under the customer=s real alternative rate.  
The rate will be the customer=s best option without shifting, less the value to  
NSPI of the shift.  
Above the line customers will be kept whole.  
171 NSUARB NSPI-P-878  
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254  
The parties will continue their discussions and ask the Board not to make a final decision on  
RTP issues pending the presentation by NSPI of a specific proposed rate option in the next  
general rate case consistent with these principles.  
6.4  
Findings  
The Board notes that the evidence presented during the hearing focused on  
[144]  
the problems associated with the RTP rate. The Board concludes that there are no major  
concerns with respect to the price signals associated with the other below-the-line rates and,  
therefore, no modifications to other rates are required at this time. The Board recognizes that  
there were a variety of concerns presented with respect to the RTP rate and it appears clear  
that the rate, as presently structured, does not function as intended.  
[145]  
The Board is satisfied that the principles set out in the above Statement form  
a suitable basis for the development of an acceptable RTP rate design. Accordingly, the  
Board agrees to defer the RTP rate design issue until the charges for the ELIIR are approved.  
It is the Board=s understanding that the parties will continue to work towards reaching a  
consensus on the RTP rate design. The Board also agrees with the comments of several  
Intervenors, who were not involved in the negotiations resulting in the Statement, that A...the  
next round of RTP discussions involve all existing and former RTP customers, potential new  
RTP customers and any interested stakeholders@. The burden will, of course, be on NSPI to  
justify its proposed rate to the Board.  
(Board Decision, Generic Rate Hearing, August 1, 2003, para. 143-145)  
[519] The Board had a follow up hearing in October/November 2003 to consider approval of the  
Real Time Price Rate Design, AAR=s for 2002, 2003, 2004 and ELIIR charges for 2004.  
[520] The Board, in its decision dated November 21, 2003172, noted the process followed by NSPI  
and intervenors to achieve a unanimous agreement on these issues:  
[12]  
Following a series of meetings between NSPI, SEB and Dr. Stutz, NSPI filed revised  
Supplementary Evidence (Exhibit N-26), dated November 3, 2003, which outlines a settlement  
agreement between the parties with respect to the AARs and the development of a new  
2P-RTP which would operate in addition to the existing RTP (1P-RTP) rates and provide  
greater flexibility for customers.  
[13]  
At the hearing on November 4, 2003, Mel Whalen, Director of Regulatory Affairs and  
Rates for NSPI, read into the record an agreed-upon revision to Appendix A-1 of Exhibit N-26.  
Mr. Whalen confirmed that Exhibit N-26, with the revision noted, constituted the final  
settlement agreement with respect to AARs for the period in question, and the new 2P-RTP.  
The settlement agreement, including the revision noted by Mr. Whalen, is attached in its  
entirety as Appendix C to this decision. NSPI also advised that 2P-RTP component of the  
172NSUARB-NSPI-P-879  
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255  
settlement agreement conforms to the three principles endorsed by the Board in its August 1,  
2003 decision on Generic Rate Design, supra.  
[14]  
According to Exhibit N-26, the parties agree on the main points of contention with  
respect to the 2P-RTP, namely the methodology used to establish the Customer Baseline  
Load ("CBL") and the issue of exports. Further, NSPI's evidence states that:  
NSPI would note that while the proposed settlement agreement was partially  
arrived at on an issue by issue basis, it was, for the most part, developed as  
a total package which results in adjustments to both the 2P-RTP proposal  
and certain of the AAR's.  
The issues addressed by this settlement agreement with respect to the AAR's  
primarily impact 2003 and 2004, neither of which is expected to be a rate  
case year. The proposed settlement, and its associated financial impact  
therefore, will not affect any above-the-line customers.  
[15]  
The highlights of the settlement agreement, with respect to the new 2P-RTP, include  
allowing the customer to propose alternative methods of developing an Annual Hourly Load  
Shape ("AHLS"), and the CBL, with the burden on the customer to show the resulting AHLS  
and CBL are reasonable; eligible customers must choose either the 1P-RTP or the 2P-RTP;  
use of a twenty-minute ahead forecast of system marginal costs, excluding electricity export  
impacts; and the inclusion of a provision for export margin sharing.  
...  
[17]  
Dr. Stutz filed evidence dated October 20, 2003 and October 24, 2003  
(Exhibits N-27 and N-28) concerning his recommendations for the AARs and the proposed  
2P-RTP. He also gave evidence at the hearing regarding his support for the settlement  
agreement, as revised. His opening statement (Exhibit N-29) states as follows:  
NSPI and SEB have reached an agreement ("the Settlement") which  
provides a Two-Part Real Time Price (2P-RTP) rate design and resolves all  
of the issues related to the Annually Adjustment Rates (AAR's). I participated  
in the negotiations which led to the development of the Settlement. In my  
view, the Settlement provides a reasonable resolution of the issues raised in  
this proceeding for all years through 2004. I urge the other parties to support  
the Settlement, and the Board to adopt it in its Decision and Order.  
The Settlement addresses the issues raised in my evidence and resolves  
them in a reasonable fashion:  
$
For the 2P-RTP rate, I recommend adoption of NSPI's proposed rate  
design with six changes. The settlement adopts NSPI's proposal with all of  
my changes.  
$
While the Incremental Export Benefit credit differs in formulation for  
my proposed Export allowance, it is reasonable. The 15% cap provides a  
benefit to other ratepayers absent in my proposal.  
$
I recommended that exports be excluded when calculating GRLF,  
IEIR and ELIIR charges. The Settlement incorporates this change for 2003,  
and 2004.  
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The three points just listed address the major concerns raised in my evidence. The Settlement  
also provides for a downward adjustment of approximately [$]800,000 to the Mersey and IEIR  
rates. This adjustment settles a number of remaining issues including items b), c), and d)  
listed in Appendix B of NSPI's supplemental Evidence. Based on my participation in the  
negotiations, I believe that such an adjustment was the only way to settle these issues, and  
that the result produced by the adjustment is reasonable. In particular, without any admission  
by NSPI or any finding against NSPI on the merits, the adjustment addresses the 2002 AAR's  
and the interruptible load for 2003 in a fashion consistent with my evidence on these matters.  
Based on my review of all the issues in this proceeding, including those raised by Dr.  
Rosenberg in his evidence concerning the 2004 AAR's, I believe the adjustment, together with  
the other parts of the Settlement, produces a reasonable result.  
[18]  
Those Intervenors who participated in the AAR and RTP rates phase of the  
proceeding confirmed to the Board that they agreed with the settlement proposal negotiated  
between NSPI and SEB, with the assistance of Dr. Stutz. Those supporting the agreement  
include ECANS, CME, MEUNSC, the Province and Quetta. While every Intervenor to the  
proceeding as a whole is not included in this group, all those Intervenors present for the AAR  
and RTP phase of the hearing did indicate their support for the settlement.  
(Board Decision, November 21, 2003, para. 12-18)  
[521] The Board approved the unanimous agreement submitted by all parties and concluded that:  
FINDINGS  
[19]  
The Board has carefully reviewed all the evidence presented with respect to the  
AARs's and RTP rates in this proceeding. The Board particularly notes that those Intervenors,  
including ECANS, CME, MEUNSC, the Province and Quetta, who have an interest in these  
matters, support the settlement agreement. The Board also notes that Dr. Stutz, who  
independently reviewed the agreement, is satisfied that the agreement represents "... a  
reasonable result." As is the case with the agreement on depreciation, the Board notes that, in  
the absence of a general rate application, this agreement has no impact on rates for  
above-the-line customers. The Board also is aware that the agreement achieved is the result  
of an extensive consultation process between NSPI and the below-the-line customers who  
are potentially impacted by the adjustments, together with input from Dr. Stutz.  
...  
[22]  
These comments apply equally to this phase of the hearing. In view of the support of  
the agreement by those Intervenors with an interest in this phase of the hearing, and in view of  
the evidence of Dr. Stutz, the Board is satisfied that the proposed methodologies for  
calculating and applying the AARs and the 2P-RTP are fair and reasonable. Accordingly, the  
Board finds it is both reasonable, and in the public interest, to approve the settlement  
proposal. The Board accepts the settlement proposal as outlined in Exhibit N-26 and revised  
by Mr. Whalen (Appendix C), and approves, in principle, the revisions to the AARs and the  
proposed new 2P-RTP which will result from the application of the revised settlement  
agreement to the formulation of these rates.  
(Board Decision, November 21, 2003, para. 19-22)  
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[522] The Board understands that NSPI=s proposed addition to the 2P-RTP tariff is to satisfy the  
third principle of the 2P-RTP design that Aabove the line customers will be kept whole@. SEB, on  
the other hand, is suggesting that if the proposed addition is approved, the cost to ELIIR will rise.  
[523] The Board has reviewed its previous two decisions, noted above, in which the 2P-RTP was  
approved. It is the Board=s view that the three principles under which this rate was approved and,  
unanimously supported by all parties, clearly state that the above the line customers are to be kept  
whole.  
[524] The language in the current 2P-RTP tariff was the subject of detailed discussion. It was  
supported by both NSPI and SEB when originally implemented.  
[525] The Board has decided that ELIIR will be substantially redesigned for 2007. The redesign  
will affect the 2P-RTP rate used in conjunction with ELIIR.  
[526] In light of the unanimous support for the language in the existing 2P-RTP rate and the  
likelihood of substantial change effective January 1, 2007, the Board has decided not to approve any  
changes in the tariff wording at this time. The Board approves the 2P-RTP rate in its current form  
effective January 1, 2006.  
10.5 Extra Large Industrial Interruptible Rate (ELIIR)  
[527] ELIIR was first approved by the Board in 2003173 and is available to large industrial  
customers who have a service voltage of at least 138 kV, and are subject to supply interruptions and  
economic interruptions as per the Board approved tariff.  
173NSUARB-NSPI-P-877  
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[528] SEB is proposing a new BTL rate, known as the FP-DSM/DR rate, as defined below, to  
replace the ELIIR rate. The new rate is described as being cost-based.174 Dr. Stutz is proposing that  
for 2006 an interim ELIIR rate be approved based on the LIIR with credit for economic  
interruptibility and that the Board hold a hearing in 2006 to approve a new BTL rate, which will be a  
successor to ELIIR.  
10.5.1 Submissions - NSPI  
174Exhibit N-61, p. 14  
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[529] NSPI proposes that, for the period January 1, 2006 to December 31, 2006, the ELIIR monthly  
customer charge be set at $24,100 and the energy rate be set at $60.80/MWh, assuming an 85% load  
factor level.175 NSPI states that the customer charge and energy rate have been calculated using the  
original formula approved by the Board in 2003, and that the resulting increases are driven by higher  
fuel costs.  
[530] NSPI also states that, if ELIIR customers provided accurate hourly demand forecasts on a day  
ahead basis, benefits would accrue to all customers. NSPI requests that the following Special  
Condition 5 be included in the ELIIR tariff:  
The customer shall, by 10 am each day, provide NSPI=s operations personnel with accurate  
hourly demand forecasts on a day-ahead basis. These forecasts will provide ongoing 168 hour  
(7 day ahead) energy requirements. The customer is to alert NSPI of any known changes to  
this forecast with a minimum of three hours advance notice on the day such changes are  
required.  
(Exhibit N-155, August 5, 2005 letter, p. 5)  
[531] NSPI responded to the Forest Product-Demand Side Management - Demand Reduction (AFP-  
DSM/DR@) rate (described below) proposed by SEB as follows:  
The rate proposed by Bowater Mersey Paper Company and Stora Enso Port Hawksbury  
Limited (respectively >BMPC@and ASEPH@and collectively ASEB@) is not cost based. The  
rate produces less than the cost of service and provides less BTL revenue.  
In order to maintain recovery of the necessary revenue requirement if SEB=s rate proposal is  
accepted, the revenue shortfall must pass to other customer classes. NSPI=s estimate of the  
shortfall in revenue from BTL rates plus associated increases to fuel costs that would result, is  
an increase to ATL classes of approximately $33-35 million.  
175Exhibit N-155, August 5, 2005 letter, p. 5  
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Given the legislative entitlement of NSPI to recover its cost of service, approval of the SEB  
proposal requires the Board to determine if it is appropriate to approve a rate that provides for  
such an increase to other rate classes. NSPI expects that other customers and stakeholders  
will have comment for the Board to consider in making this decision.  
(Exhibit N-88, pp. 1-2)  
[532] Board Counsel explored NSPI=s position on what Astandard@it used to determine if BTL  
rates have met the cost of service test. The following exchange occurred during his cross  
examination of the NSPI=s rates panel:  
Q:  
Now, just turn to page 2, if you would, under Item 2, ACost of Service,@the second  
paragraph, and this has been restated a number of times in various ways both in your  
evidence here and in other parts of the pre-filed. It says:  
AThe proposed SEB rate would not recover the associated  
cost of service.@  
And as I understand itB and we discussed this previouslyBwhen you say  
"cost of service" in the context of this rate, you=re talking about the cost of  
service reflected in the formula?  
A:  
(Boutilier) Yes, and the inputs to that formula which areC  
Q:  
A:  
And the inputs to that formula.  
(Boutilier) ---- based on cost, yes  
Q:  
A:  
And that=s always the standard that you=re referring to when you talk about cost of  
service and costs being shifted to other customers?  
(Boutilier) Yes, there are very explicit costs in that formula and NSPI=s projection of  
those costs for 2006 are used explicitly.  
(Transcript, November 15, 2005, pp. 367-368)  
[533] NSPI addressed both the FP-DSM/DR rate and Dr. Stutz=s proposed new rate to replace the  
current ELIIR in its Closing Argument. NSPI argued that it has computed the 2006 ELIIR rate in  
accordance with the Board approved formula and forecast costs for 2006. Adoption of the FP-  
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DSM/DR rate as proposed by Dr. Rosenberg is not cost based and would result in the transfer of $33  
to $35 million to ATL customers.176  
[534] As to Dr. Stutz=s proposed new rate (see discussion below), NSPI states that it is an  
inadequate compromise between the ELIIR rate computed by NSPI and the SEB proposal. It would  
require ATL customers to pay an additional $13.1 million.177 NSPI referred to Dr. Stutz=s  
statement in which he is proposing Ato make an adjustment on an admittedly somewhat ad  
hoc basis to get a result which I believe is reasonable for 2006."178 NSPI stated that this ad  
hoc proposal violates many of Bonbright=s principles of a sound rate structure and urged  
the Board to reject the proposed rate.  
[535] NSPI also recommends that the Board should direct that a proper process of rate design  
making take place for ELIIR and 2P-RTP in 2006.179  
10.5.2 Submissions - Intervenors and Dr. Stutz  
176NSPI, Redacted Closing Argument, p. 79  
177NSPI, Redacted Closing Argument, p. 80  
178Transcript, December 2, 2005, p. 3559  
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179NSPI, Redacted Closing Argument, p. 83  
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[536] SEB (Stora and Bowater) are currently the only customers on the ELIIR rate. Witnesses for  
SEB included Elizabeth Beal, President and CEO, Atlantic Provinces Economic Council, who  
provided evidence on the importance of the forest industry to the economy of Nova Scotia. Her view  
is that the forest industry is a vital contributor to the economy of Nova Scotia.  
[537] Dr. Rosenberg, on behalf of SEB, filed evidence on September 19, 2005180, in which he  
proposed a new rate to replace the ELIIR rate. He also filed evidence on October 17, 2005181 in  
which he proposed modifications to the inputs used by NSPI to compute the ELIIR rate.  
[538] In addition, Dr. Rosenberg commented on NSPI=s proposed Special Condition 5 (day ahead  
forecasts) for the ELIIR rate, stating that SEB would be willing to make efforts to help NSPI lower its  
fuel costs in the future, but it would only be fair that it be part of a viable and economic rate.182  
Forest Product - Demand Side Management/Demand Reduction Rate (FP-DSM/DR  
Rate)  
[539] Dr. Rosenberg describes SEB=s reasons for proposing a new rate as follows:  
180Exhibit N-61  
181Exhibit N-91  
182Exhibit N-91, p. 37  
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Both Stora Enso and Bowater find themselves in a precarious position. As the Board is well  
aware, these two Companies rely on affordable electricity supply to remain economically  
viable. Effective April 1 of this year, the Board approved a 5.4% increase for the Above the  
Line classes, but a 10.4% increase for the ELIIR. On July 5, only four months after that Order,  
NSPI filed a general rate application requesting an additional 14.7% increase for the Above  
the Line customers for 2006. On August 5, NSPI filed for a 30% increase for the ELIIR rate. In  
other words if the NSPI application is approved, SEB will experience a 40% increase from  
rates that were in effect just 9 months ago. From almost any perspective, this constitutes  
rate shock. Obviously, this situation is untenable. The ELIIR rate is not working and so I am  
proposing a new below the line rate to supplant the ELIIR. [Emphasis added in original]  
(Exhibit N-61, pp. 2-3)  
[540] Dr. Rosenberg=s opinion is that the ELIIR currently does not provide a discount to ELIIR  
customers that is commensurate with its value to the NSPI system.  
[541] He proposes to replace the ELIIR with a new BTL rate; the FP-DSM/DR Rate. The features  
of the new rate are described by Dr. Rosenberg as follows:  
Q.  
ARE YOU BASING YOUR PROPOSED NEW BELOW-THE-LINE RATE ON ANY  
PARTICULAR ECONOMIC DEVELOPMENT OR LOAD RETENTION RATE?  
A.  
No. I have simply pointed out that rates with those specific objectives are not out of  
the ordinary. However, I believe the new FP-DSM/DR Rate, if such a rate is approved  
by the Board, should be based on the particular circumstances, history and  
predicament of the involved customers, NSPI and the province of Nova Scotia, as well  
as the evidence in this case of course.  
Q.  
A.  
WHAT FEATURES ARE YOU RECOMMENDING FOR THE NEW FP-DSM/DR  
RATE?  
I am proposing a rate with the following features:  
1.  
2.  
It will be simpler than the current and 2-Part RTP amalgam, hopefully  
to avoid the controversies and disagreements that have plagued the  
implementation of those rates. It will also be more flexible than its  
predecessor.  
It will be set for an initial period of a minimum of three years to  
provide a degree of stability to both the customers on the rate as well  
as to NSPI. Thereafter, following the expiry of each three-year  
period, the rate can be reset either at the request of NSPI or on the  
volition of the customers on the rate, for a further three-year period.  
For the first three-year period, this request can be made any time  
after July 1, 2008, with an effective date of change no later than six  
months after the request and no earlier than January 1, 2009; and so  
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on for subsequent three-year periods. Any change, of course, would  
have to be approved by the Board.  
3.  
It will be completely interruptible, for either supply or economic  
reasons, with 10 minutes notice for supply and 30 minutes notice for  
economic reasons, but with limitations on frequency, duration of  
events, and length between events. There is no compensation to the  
customer for these called interruptions, but the customer can buy  
through economic interruptions at actual incremental cost plus $5 per  
MWh. (It cannot buy through supply-related interruptions.)  
4.  
5.  
Unlike the ELIIR, which can only be interrupted for avoiding  
combustion turbines or importing high-priced energy, the FP-  
DSM/DR Rate could be economically interrupted for any reason, at  
the discretions of NSPI.  
At any time, the utility can offer to buy interruptions at whatever rate  
the utility believes will be attractive to the customer yet beneficial to  
the utility. This last feature was suggested by Dr. Stutz at the July 20  
meeting on AARs.  
6.  
7.  
Customers on the rate will be required to provide hourly forecasts of  
their load.  
The rate will pass the due discrimination test. I will explain this test  
in more detail after I have described the specific rate that I propose.  
Q.  
A.  
WHAT AVAILABILITY REQUIREMENTS ARE YOU PROPOSING FOR THIS RATE?  
I am proposing the same availability criteria that are currently included in the ELIIR,  
with but four exceptions.  
$
$
The ELIIR is currently limited to 275 MW. I would propose that this limitation  
be excluded for the current rate.  
The ELIIR rate specifies that customers on the rate must be able to provide at  
least 20 MW of interruption. I propose that the term A20 MW@be replaced by  
the term Asignificant blocks@to allow for greater flexibility.  
$
$
The ELIIR rate limits the rate to those customers taking service at 138 kV or  
above. I propose just requiring that customers take service at Atransmission  
voltage@to make the rate more accessible.  
The customer must be reasonably expected to maintain a high monthly load  
factor, and has demonstrated this ability on a historic basis.  
Q.  
WOULD THE CUSTOMER STILL BE REQUIRED TO PROVIDE CREDIBLE  
EVIDENCE THAT A SIGNIFICANT PORTION OF THEIR ANTICIPATED USAGE ON  
THE FP-DSM/DR RATE IS AT RISK?  
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A.  
Yes. However, as the FP-DSM/DR Rate is intended to supercede the ELIIR, the new  
tariff should specify that customers formerly approved by the Board for ELIIR would  
be considered eligible for this new below-the-line rate as well.  
Q.  
A.  
WHAT RATE FORMAT ARE YOU PROPOSING?  
I propose a rate with just four elements. The first is a demand charge based on a  
Contract Demand (CD). The contract demand could be changed only once every  
twelve months with 30 days written notice, with the following limited exceptions:  
$
By February 28 of each year, the CD could be lowered for the remainder of  
the calendar year for market reasons, but by no more than 10% of the  
existing CD.  
$
The CD could be reduced for a planned shutdown period; such shutdown  
periods cannot occur more than twice in any calendar year and must be  
specified three weeks in advance.  
$
$
The CD could be changed for a permanent alteration of production capacity  
or a DSM initiative.  
The CD could be suspended for force majeure reasons.  
The Contract Demand charge is intended to make a contribution to NSPI=s fixed  
generation and transmission costs.  
The second element is an energy charge that would recover NSPI=s average fuel  
costs (plus variable O&M and losses) if its entire system exhibited a 100% load factor,  
i.e. a perfectly flat load. This energy charge would apply to all energy (except buy-  
through energy) up to the Contract Demand.  
The third element is an excess energy charge for all energy taken above the Contract  
Demand in any hour.  
The fourth element is a cost based monthly customer charge.  
(Exhibit N-61, pp.11-14)  
[542] Dr. Rosenberg calculated that the FP-DSM/DR rate as proposed, at an assumed 85% load  
factor, would produce a combined rate of approximately $46.10 per MWh.183 In response to Dr.  
183Exhibit N-61, p.24  
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267  
Stutz=s IR-7, he recalculated his proposed rate using the same assumptions as NSPI and it was  
$48.85 per MWh.  
[543] In Dr. Rosenberg=s view, his proposed rate is cost based in the same sense as NSPI=s  
witnesses maintained that ELIIR was cost based, when that rate was first being presented to the Board  
for approval. However, he does note that, if one were to adopt the view expressed by Dr. Stutz in the  
Generic Rate Design proceeding, then his proposed rate may not be considered cost based.184  
[544] In response to an information request from NSPI, where the suggestion was made that  
domestic customers would be subsidizing SEB through increased rates, Dr. Rosenberg=s response  
included the following statement:  
...He would add, however, that the rate he is proposing can by no means be characterized a  
request to Asubsidize SEB through increased domestic rates@, the ultimate amount of which  
are in any event within the domain of the UARB.  
(Exhibit N-77, NSPI-SEB -IR-5)  
[545] SEB responded to intervenor objections to the proposed FP-DSM/DR rate. In summary,  
SEB=s position is that the FD-DSM/DR rate is cost based and SEB is not requesting a special  
discount or a rate driven solely by competitive pressures. It is not requesting a subsidy, but is simply  
requesting a rate that reflects the actual cost of service.185  
184Exhibit N-61, p. 23  
185SEB Rebuttal Closing Submission, pp. 2 and 7  
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Intervenor Responses to the proposed FP-DSM/DR Rate  
[546] Many of the intervenors filed evidence in response to the proposed FP-DSM/DR rate, or  
commented on the rate in their closing submissions. None of these intervenors supported the  
proposed rate. Many commented on the impact that the FD-DSM/DR would have on ATL rates.  
[547] Mr. Drazen filed evidence in response to the proposed FP-DSM/DR rate on behalf of Avon.  
He summarizes his main points as follows:  
A. First, the increase to ELIIR customers is a higher percentage than to other customers  
because (1) ELIIR was set Abelow formula@in the previous case and, (2), ELIIR is by design  
more fuel intensive than other rates. Second, the rate proposed by Dr. Rosenberg=s  
September evidence is not an accurate reflection of the cost of serving the ELIIR loads.  
Overall, the FP-DSM/DR proposal shifts a large amount of costs from ELIIR customers to the  
above-the-line (ATL) customers.  
(Exhibit N-100, p. 2)  
[548] Ms. Brockway filed evidence for the Consumer Advocate responding to the proposed FP-  
DSM/DR rate. In her evidence, Ms. Brockway uses both the SEB response to Dr. Stutz IR-8 and  
NSPI=s filed evidence186 to conclude that the adoption of the FP-DSM/DR rate would transfer costs  
to the ATL customers and would result in a higher rate increase for these customers.  
...The proposal of the below-the-line customers should be rejected unless they meet a heavy  
burden of demonstrating that such subsidies to their rates are not unjustly discriminatory,  
unfair, and otherwise violative of sound ratemaking criteria.  
(Exhibit N-99, p. 2, lines 19-22)  
186Exhibit N-88  
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[549] She concluded that the Board should not approve the FP-DSM/DR rate based on the state of  
the evidentiary record.187  
[550] Dr. Stutz provided evidence on the proposed FP-DSM/DR rate. His recommendation is that  
the rate not be approved. The key points of his evidence are as follows:  
$
$
The FP-DSM/DR does not provide either reasonable cost recovery or an appropriate  
credit for economic interruptibility.  
For a non-cost based rate to be approved there needs to be evidence that the rate  
provides the minimum cost reduction required to retain load. Based on the information  
available, it is not possible to determine if the FD-DSM/DR rate satisfies this  
requirement.  
(Exhibit N-98, p. 2, lines 5-11)  
[551] In their Closing Submissions, Avon, ECANS, MEUNSC and the Province all opposed the FP-  
DSM/DR rate. Many commented on what they saw as a transfer of costs from BTL customers to  
ATL customers.  
[552] Avon states:  
[251] The Forest Products Rate is a non-starter. It is lower than the current rate when both  
fuel and non-fuel costs have risen. It is devoid of any reasonable justification, any reasonable  
connection to the cost of serving SEB and has no prospect for public acceptability by the  
above the line customers who would be required to provide a massive subsidy to Stora Enso  
and Bowater.  
(Avon, Redacted Closing Submission, p. 53)  
[553] ECANS=position is stated as:  
... More pointedly, if SEB are granted special status by having access to rates at less than  
cost, then any shortfall will be assigned to Above-the-Line customers. In NSPI=s N-88, a $33  
million transfer of costs would result in a 3%+ increase in the ABL classes. This is not  
acceptable.  
187Exhibit N-99, p. 9  
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270  
If SEB need lower electricity rates to remain competitive in their markets, they should look to  
Government and the taxpayer to address the challenge. Economic subsidization is not within  
the Board=s mandate.  
(ECANS, Redacted Closing Submission, pp. 14-15)  
[554] In his Closing Submission, the Consumer Advocate takes the position that it will not address  
the FP-DSM/DR rate on the basis that the design of a new rate part way through the proceeding is  
@rate design on the fly@, and is not the appropriate regulatory approach.188  
ELIIR Modifications/Replacement  
[555] Dr. Rosenberg=s evidence recommends a number of changes to the NSPI computations of the  
ELIIR rate. The changes were proposed in the eventuality that the FP-DSM/DR rate is not accepted  
or not accepted prior to January 1, 2006.189 Dr. Rosenberg states that his computed reduction still  
results in rates that are far too high to characterize as competitive and these reductions do not lessen  
the need for the FP-DSM/DR rate.190  
188Consumer Advocate, Redacted Closing Submission, p. 15, para. 59  
189Exhibit N-91, p. 23, lines 18-22  
190Exhibit N-91, p. 31, lines 13-19  
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Dr. Stutz=s ELIIR Adjustment  
[556] As previously mentioned, Dr. Stutz recommends that a successor to the ELIIR should be  
developed. In his evidence, Dr. Stutz provided some comments on the type of rate that should replace  
ELIIR:  
... ELIIR and FP/DSM-DR both provide a credit in exchange for interruptibility. However, they  
do not specify the credit directly. Rather, they build it in through the design of their charges.  
Instead, one should begin with LIR, the cost-based rate on which SEB would take service if it  
were not interruptible and add an explicit economic interruptibility credit to the existing rider for  
supply interruptibility. A rate designed this way would be preferable to ELIIR or FP/DSM-DR  
because the value of interruptibility would be stated clearly and directly. Development of this  
rate should include a thorough review of the value of supply and economic interruptibility. If  
LIR with the appropriate credits for interruptibility does not meet SEB=s business needs, SEB  
could ask the Board to add a separate rider for load retention.  
(Exhibit N-98, p. 9, lines 6-16)  
[557] Dr. Stutz >s position, as outlined in his opening statement, is that the time has come to set a  
firm schedule to replace ELIIR with a new rate.191 He added that this issue should be settled by the  
end of 2006. Dr. Stutz=s opening statement provided further detail on what adjustments are required  
to the NSPI=s filed ELIIR rate and how the rate may be computed from the Large Industrial  
Interruptible Rider (LIIR) rate:  
A key feature which distinguishes ELIIR from the Large Industrial Interruptible Rider (LIIR) is  
economic interruptibility. To be fair to those served on ELIIR and to other ratepayers, the cost  
of service on ELIIR needs to be roughly equal to the cost of service on LIIR less the likely cost  
of buy-through. ...Thus, based on the assumptions in NSPI=s filing, an adjustment of about  
$6.30 to NSPI=s proposed ELIIR energy charge is needed. This adjustment simply allows the  
savings due to economic interruptions to pass through to the customers on ELIIR who made  
the savings possible.  
(Exhibit N-244, p. 3)  
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191Exhibit N-244, p. 2  
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[558] During cross-examination by Al Dominie of MEUNSC, Dr. Stutz explained that he  
recommends a two step process for dealing with ELIIR: first, to put an appropriate ELIIR charge in  
place for 2006; and the second, is to replace ELIIR with a new rate. The first step is what needs to be  
accomplished as part of this proceeding.192  
[559] Dr. Stutz filed Exhibit N-241, which provided a computation and proposed ELIIR rate for  
2006. The resulting average adjusted ELIIR rate is $54.89/MWh.  
[560] During cross-examination by Mr. Grant, Dr. Stutz stated that the savings to SEB under his  
proposed ELIIR rate for 2006 using a rate of $54.89/MWh versus the proposed NSPI ELIIR and 2P-  
RTP rates would be approximately $13 million.193 Dr. Stutz provided details of the computation  
(along with some comments on the computation) in response to Undertaking U-88. He did not agree  
with the characterization by Mr. Grant that this would transfer $13 million to ATL customers. It is  
his view, that Awe=re simply setting the rate correctly@.194  
[561] Dr. Stutz was also cross-examined on the impact of his proposed ELIIR adjustments on other  
ratepayers. The following exchange occurred between Dr. Stutz and Mr. Grant:  
192Transcript, December 2, 2005, p. 3546  
193 Transcript, December 2, 2005, p. 3530  
194 Transcript, December 2, 2005, p. 3547  
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Q:  
A:  
Thank you. Dr. Stutz, have you calculated whether rate payers who are not on the  
ELIIR rate would be better off having Stora Enso Bowater under the rate as you  
propose to modify it than not at all?  
I haven=t calculated it, but I think it=s clear that they=re better off with them than  
without them. And the reason I say that is that my rate charges them based on the  
LIR, which is an above the line, cost based rate, and the difference is a credit which,  
by design, their economic interruption finances. So unless it=s undesirable to have  
customers on the LIR rate, it follows that it=s economically desirable to have them on  
my version of ELIIR.  
Q:  
A:  
It=s clear, though, is it not, that for the other rate payers it=s preferable to have Stora  
Enso Bowater on the existing ELIIR rather than on the ElIIR as you=ve proposed?  
Absolutely.  
(Transcript, December 2, 2005, p. 3534)  
[562] Dr. Rosenberg addressed Dr. Stutz=s proposal in his opening statement:  
... I acknowledge that Dr. Stutz=s top-down approach to a replacement to the ELIIR formula  
could be workable and may engender less controversy than the bottom up approach that I had  
proposed in my FP testimony. In fact, in my Rebuttal testimony I showed how such a top-  
down approach could be used to fashion the FP DSM/DR rate by subtracting the value of  
interruptibility from a suitably adjusted Large Industrial Rate, and how the result of such a top-  
down approach compared to the rate that I had initially derived. I use the words Asuitably  
adjusted@because it is necessary to first distinguish between the physical cost of serving the  
FP customers, as opposed to serving LIR customers, before we can even begin to account for  
the value of interruptibility.  
(Exhibit N-235, p. 2)  
[563] Dr. Rosenberg went on to state that:  
While I have adopted Dr. Stutz=s recommended value-driven methodology (adjusted as I have  
recommended), to derive the overall dollar figure for the rate, I maintain my recommendations  
for the form of the replacement for ELIIR i.e. I continue to recommend the FP rate form.  
(Exhibit N-235, p. 2)  
[564] In general, other intervenors took the same position on Dr. Stutz=s proposed rate as they did  
on Dr. Rosenberg=s FD-DSM/DR rate. For example, ECANS states that neither proposal is  
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acceptable195, the Consumer Advocate states there should be no adjustment to the ELIIR rate, or  
alternatively, less than that proposed by Dr. Stutz196, and Avon submits that Dr. Stutz=s adjustment  
should not be made for 2006197.  
10.5.3 Findings  
[565] NSPI is proposing that the new ELIIR monthly charge be $24,100 and the energy rate be  
$60.80 per MWh (at 85% LF) effective January 1, 2006 to December 31, 2006. This results in an  
approximate combined ELIIR rate of $61.19 per MWh. NSPI states that the main reason for the  
increase in the proposed ELIIR rate is substantially higher fuel costs in 2006. It further submits that  
the proposed rate is based on the formula approved by the Board and that any changes to the formula  
should be reviewed in a separate hearing in 2006 for a rate to be effective in 2007.  
[566] SEB has taken the position that the proposed 2006 ELIIR rate, calculated based on the current  
formula, is not workable and does not achieve the results it was intended to achieve. SEB has  
proposed the new FP-DSM/DR rate, which it claims is based on the actual cost of service for this  
customer class.  
195ECANS, Redacted Closing Submission, p. 14  
196 Consumer Advocate, Redacted Closing Submission, p. 2  
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197 Avon, Redacted Closing Submission, p. 55  
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[567] Dr. Stutz is of the view that the ELIIR should be replaced with a new rate to directly reflect  
credits for economic interruption. He is suggesting that a reasonable solution would be to start with  
LIIR and create a formula to apply appropriate credits. He is also of the view that a separate hearing  
should be held in 2006 and a new rate be approved no later than the end of 2006. In the meantime, he  
recommends a temporary ELIIR rate of $54.89/MWh for 2006.  
[568] All other intervenors have objected to the suggestions by SEB and Dr. Stutz because they  
would result in a shift in the revenue requirement from the BTL customers to the ATL customers  
without following the normal due diligence process for approving new rates.  
[569] The Board has carefully considered the evidence and submissions on this issue. The Board  
concludes that the FP-DSM/DR rate proposed by SEB is not cost based and would create an undue  
burden on ATL customers. Accordingly, the Board is not prepared to approve the FP-DSM/DR rate.  
[570] It is clear to the Board that ELIIR is not working as it was originally intended to by both NSPI  
and SEB. For whatever reason, it does not appear to provide reasonable compensation for economic  
interruptibility. Therefore, the Board will hold a separate hearing in 2006 to consider a replacement  
for ELIIR, which will become effective January 1, 2007. The Board directs NSPI to file an  
application for a new rate to replace ELIIR, after consultation with its customers, no later than June  
30, 2006.  
[571] For the current year, the Board has been presented with two cost based approaches for setting  
the energy charge in ELIIR. NSPI supports the use of the formula in the existing tariff. The Board  
understands that Dr. Stutz recommends beginning with the LIR - that is the Large Industrial Rate at  
an 85% load factor, less the transformer ownership credit and the value of the interruptible supply  
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credit of $3.43 per month per kVa. Dr. Stutz then subtracts the value of economic interruptibility,  
which he calculated at $8.43 per MWh. Each of these approaches has strengths and limitations. The  
ELIIR formula has been approved but, for 2006, does not appear to provide reasonable compensation  
for economic interruptibility. Dr. Stutz=s approach is conceptually correct, but does not provide a  
fully developed alternative for ELIIR. To give weight to each approach, the Board directs NSPI to  
set the ELIIR energy charge by averaging the results produced by the two approaches.  
[572] In setting the ELIIR energy charge, the Board directs NSPI to use the fuel budget, and all  
other items having an impact on ELIIR, as approved in this decision. The Board also directs NSPI to  
iterate its rate calculations, to ensure consistency between the LIR charges used to set ELIIR and  
those to be paid by customers on the LIR.  
[573] As previously indicated, the Board has directed NSPI to develop and file a replacement for  
ELIIR. Both NSPI and SEB have agreed that Dr. Stutz=s approach to the development of such a  
replacementCbeginning with a firm rate and then specifying credits for interruptibilityChas merit.  
While the Board concurs, it would be prepared to consider other viable options which may be  
developed.  
[574] NSPI proposed to add Special Condition 5 to the ELIIR tariff, the purpose of which is to  
require customers to file an hourly demand forecast on a day-ahead basis. Because the current  
version of ELIIR is about to be replaced, the Board will not approve any changes in the present tariff  
language. Upon filing, the Board will approve, effective January 1, 2006, the interim ELIIR rate  
calculated in accordance with this decision.  
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11.0 OTHER ISSUES  
11.1 Load Forecast  
[575] The details of NSPI=s load forecast for the test year are provided in the 2006 Load Forecast  
Report appended to the Company=s application as Exhibit N-2, Appendix F. Further information in  
support of the load forecast is contained in Exhibit N-1, pp. 162 to 179. In-province electric energy  
sales are forecast to grow by 1.2% in the 2006 test year despite an average annual growth rate of  
2.6% over the past five years. NSPI states that the reduced growth rate for the test year is reflective  
of the impact of existing DSM initiatives. In comparison to the projected figures for 2005, residential  
sector sales in 2006 are expected to rise by 1.1%, commercial sector sales by 2.1% and industrial  
sector sales by 0.5%.198  
[576] Peak demand for the winter of 2005/2006 is forecast to be 2,172 MW, a slight increase from  
the figure of 2,143 MW in the previous winter. The projected peak demand assumes a 60 MW  
reduction due to economic interruption at the time of system peak.199  
[577] In its load forecast for the 2006 test year, NSPI has accounted for the impact of ongoing DSM  
initiatives which, NSPI states, will reduce in-province electric energy sales, as well as reduce peak  
demand by 13 MW.  
198NSPI Application, Exhibit N-1, p. 162  
199NSPI Application, Exhibit N-1, p. 162  
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[578] In its response to the Province IR-55, NSPI estimated that existing DSM initiatives will result  
in a reduction of 65 GWh for the 2006 test year. This reduction was done manually by reducing its  
residential forecast by 1% (i.e., 42.7 GWh) and its commercial forecast by 0.5% (i.e., 16.7 GWh).  
NSPI=s load forecast is typically calculated using an econometric model as defined in the  
Company=s Load Forecast Report.200 As it reiterated during the hearing, NSPI asserts that DSM=s  
impact on the 2006 load forecast is the result of existing educational and awareness programs carried  
out by government and other agencies. NSPI states that the Company=s own DSM efforts will only  
commence to impact its load forecast in the 2007 test year.201  
[579] In Direct Evidence and oral testimony, Dr. Stutz expressed concern that NSPI=s revenue  
forecast for 2006 may already be too low and that the Board should not approve NSPI=s DSM-related  
adjustment to its load forecast. He stated:  
... NSPI=s statistically based residential and commercial forecasting models will reflect all  
ongoing DSM. An adjustment is only needed to account for the impact of new, incremental  
DSM activities. NSPI intends to develop new DSM initiatives. However, the specific programs  
are still unspecified. The 1.0 and 0.5 percent adjustments are based on assumptions, not  
estimates based on specific incremental DSM initiatives.  
Once specific programs are developed, time will be required to inform potential participants  
about the programs, for them to decide if they wish to participate, and for the participants to  
take the step promoted by the programs. There is almost no allowance for Astart up@ in  
NSPI=s DSM adjustment.  
...  
The impact of incremental DSM is more likely to follow and S-shaped Alogistic curve,@with  
very low impacts in the early years as knowledge of the program spreads, rapid increase in the  
middle years as the program takes hold, and decreasing growth in the later years as market  
saturation occurs.  
200Exhibit N-2, Appendix F  
201Province IR-55  
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...  
I recommend making no DSM adjustment at all. This recommendation reflects the fact that the  
1.0 and 0.5 percent impacts are an assumption rather than an estimate of the impact of a  
specific incremental DSM program, the likelihood that any effect of incremental DSM will  
phase in slowly at first, and the concern that NSPI=s underlying forecast of sales for 2006 may  
already be too low.  
(Stutz, Pre-filed Evidence, Exhibit N-81, pp. 16-17)  
[580] In cross-examination by Mr. Connors, Dr. Stutz acknowledged that Exhibit N-229 may  
provide some evidence of incremental activity in support of NSPI=s adjustment to its load forecast.202  
This exhibit outlined, according to Alan Richardson, NSPI=s General Manager, Customer Service,  
better than anticipated results of the CFL program. In the end, however, Dr. Stutz believed there  
should be a detailed analysis to support the reduced load forecast and that the survey results (i.e.,  
Exhibit N-229) are not normally the way utilities prove adjustments to their forecasts.203  
[581] During the 2005 rate case, Dr. Stutz also expressed concerns that NSPI=s sales forecast was  
too low. In its decision, the Board concurred with his view:  
[296] The Board shares Dr. Stutz=s view with respect to the load forecasting issue. The  
Board accepts his recommendation and directs NSPI to initiate meetings with Dr. Stutz and  
Board staff to attempt to resolve these concerns.  
[297] The Board also directs that a report on the progress of improvements to NSPI=s load  
forecasting methodology be filed by December 1, 2005.  
(Board Decision, March 31, 2005)  
202Transcript, December 2, 2005, p. 3576  
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203Transcript, December 2, 2005, pp. 3572 and 3576  
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[582] By letter dated November 29, 2005, NSPI requested that the Board postpone the requirement  
for the filing of this report. In a letter dated December 14, 2005, the Board agreed to postpone the  
filing of the report pending the review of this issue by NSPI and Dr. Stutz.  
[583] Several intervenors also opposed NSPI=s proposed DSM-related adjustment to the load  
forecast. Avon adopts Dr. Stutz=s concerns with respect to the adjustment, particularly in light of his  
remarks that the load forecast may already be too low. SEB submitted that NSPI did not provide  
adequate support for the adjustment, including the Company=s responses to NSDOE IR-55, SEB IR-  
131 and Exhibit N-229.  
[584] Testifying on behalf of the Consumer Advocate, Ms. Brockway expressed reservations about  
NSPI=s estimate of the impact of DSM on load projections. She stated that the Company had not  
incorporated the results of various studies and technical literature outlining the impacts that can be  
expected from different types of DSM activities.204 Ms. Brockway was specifically asked by the  
Board about NSPI=s estimated impact of DSM efforts with respect to the 2006 test year:  
Q.  
(Deveau) And I'd refer you quickly, if I could, to Exhibit N-229. And that was an exhibit  
presented yesterday by Mr. Richardson. I believe you were here when he probably  
spoke about that.  
Yes.  
A.  
Q.  
And that's -- that was an exhibit that he presented when -- based on his evidence that  
NSPI was actually experiencing penetration rates quicker than they had anticipated.  
And this is based on a survey and the extrapolations made based on the customers  
and the number of bulbs that had been installed. Do you have any comments to make  
with respect to this type of research that has been tendered?  
A.  
Well, actually, there was -- yes, I do. Thank you, Mr. Commissioner, because I would  
align myself with those comments that were either made or suggested by some that  
it's very common in survey research for respondents to give the questioner the  
204Brockway Opening Statement, Exhibit N-242  
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answer that they think the question wants, particularly when you have raised cultural  
awareness of the importance of the right answer being, "Yes, I've got more CFLs."  
And ---  
Q.  
A.  
People are embarrassed to say they haven't.  
Yes. Now, in some cases their memory has been adjusted to meet their expectations  
of themselves, and it's not a conscious lie. I'm not saying that. But the survey -- this  
kind of a survey research is well understood to be unreliable as -- certainly as the sole  
basis for estimating how much behaviour has changed. The other thing that I noted  
about this is that I would expect that the estimates of how many hours the bulbs are  
on is -- at least with respect to the five hours, that that's an over statement, that in  
very few households would an average of two and a half bulbs be on for five hours a  
day all year long. They might be in the depth of winter, but that's not all year long. So I  
think some of the wrong assumptions are being drawn from this, that the estimates  
are over stated.  
(Transcript, December 2, 2005, pp. 3505-3506)  
11.1.1 Findings  
[585] Based on its review of the evidence, the Board is not persuaded that NSPI's manual  
adjustment to its load forecast should be approved. While the survey results shown in Exhibit N-229  
are encouraging with respect to the positive impact of programs like the CFL initiative, the Board  
concurs with Dr. Stutz that this is not the appropriate way for a regulated utility to prove a reduction  
of its load forecast and, further, does not justify the manual adjustment made by NSPI.  
[586] As noted above, NSPI's load forecast is typically calculated using an econometric model.  
While the Board is mindful that DSM is a relatively new initiative, it considers that the impact of  
some DSM programs is already embedded, at least in part, in the variables comprising the  
econometric model. Moreover, the Board notes Dr. Stutz's concern that NSPI's underlying load  
forecast may already be too low for the 2006 test year. In such circumstances, the Board is reluctant  
to allow a reduction which would result in an even lower load projection.  
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[587] Based on the evidence at the hearing, the Board concludes that denying the DSM-related load  
forecast reduction would increase variable costs for NSPI by about $5.1 million, while corresponding  
revenues from electricity sales would increase by approximately $6.3 million based on NSPI's  
proposed rate increase.205 While these responses to the SEB IRs translate into a net reduction of $1.2  
million in the revenue requirement, Avon asserts that the difference could be as high as $2.0  
million.206 It is the Board's understanding that because of the potential net savings of between $1.2  
million - $2.0 million, the proposed rate increase sought by NSPI will go down. For the purpose of  
its decision, the Board=s estimate of the impact is $1.6 million. The Company is directed to address  
the impact of the Board's denial of the DSM-related load adjustment in its Compliance Filing.  
[588] As noted above, by letter dated December 14, 2005, the Board agreed to postpone the filing of  
a report by NSPI with respect to its load forecasting methodology, a report which was ordered by the  
Board in the 2005 rate decision. In its letter requesting the postponement, NSPI indicated that the  
delay would facilitate discussion of the load forecasting issues with Dr. Stutz in 2006. The Board  
directs that NSPI file its report on the progress of improvements to its load forecasting methodology  
by December 29, 2006. This extension of the filing deadline should allow NSPI to incorporate its  
response to the DSM-related load reduction issues noted by Dr. Stutz.  
205 SEB IR-227, SEB IR-131  
206 Avon, Redacted Closing Submission, p. 46  
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11.2 Unmetered Rates  
[589] HRM and the Union of Nova Scotia Municipalities (AUNSM@) contend that an inordinate  
level of costs is being assigned to the Unmetered Class, which is primarily comprised of  
municipalities. As noted by Warden Richard Cotton, President of the UNSM, who spoke during the  
evening session, the unmetered rate is of great significance to municipalities because it represents  
almost 50% of the total of municipal electric bills.207  
[590] In order to assign costs to its customer base in the Unmetered Class, NSPI uses a designated  
number of accounts as a surrogate for customers within the Class, referred to as the Aweighting  
factor@. For the C-3 Class, a weighting factor of 5.0 is applied to the number of accounts. HRM and  
the UNSM assert that this formula is not reflective of the costs actually being incurred for the  
provision of service to the Unmetered Class. In their view, the number of accounts do not bear the  
same relationship to costs as the number of customers do. They submit that municipalities use  
services such as billing or the call centre far less than other customers.  
[591] HRM retained Robert Greneman, of Stone & Webster Management Consultants, Inc., to  
review this issue. In his pre-filed evidence, Mr. Greneman submits that the weighting factor of 5.0  
for the Unmetered Class bears no relation to cost causation. He states that billing, customer service  
and call centre expenses for unmetered accounts are no greater than for residential accounts and,  
therefore, the weighting factor should not exceed 1.0. He concludes:  
207UNSM Presentation, November 23, 2005  
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NSPI should undertake a more detailed analysis of the activities that are included in factor C-  
3. I recommend that until such analysis is completed, this Board direct NSPI to set the  
weighting to the Unmetered class in factor C-3 from 5.0 to 1.0, beginning in this proceeding.  
(Greneman, Pre-filed Evidence, Exhibit N-85, p. 16)  
[592] The UNSM estimates that reducing the weighting factor from 5.0 to 1.0 would reduce  
municipal electric bills by over $1 million across the province.208  
[593] HRM states that a street lighting study was last conducted by NSPI in 1975, which forms the  
basis for the present allocation in the Cost of Service Study (ACOSS@). HRM asks that a new  
streetlight study be undertaken to ascertain the number and type of fixtures, their age and actual  
maintenance data, broken out by municipality, and that the study include a review of current  
maintenance practices across Canada to establish a Best Practices Lighting Maintenance Standard.  
The UNSM adds that such a study should include data respecting the energy consumption of  
streetlights, to assist it in developing energy reducing strategies. Further, HRM asks that the study  
gather data to determine the number and origin of calls to NSPI billing staff respecting unmetered  
services.209  
208UNSM Presentation, November 23, 2005  
209HRM, Redacted Closing Submission, p. 1  
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[594] Mr. Greneman also states in his pre-filed evidence that NSPI should identify the portion of  
rate base allocated for vehicles and plant associated with the meter reading function and that the  
Company should remove the related interest, return, taxes and depreciation from its allocation to the  
Unmetered Class.210 While HRM acknowledges that any direct costs related to meter reading were  
removed from the Unmetered Rate as a result of the last rate hearing, it asks that the same adjustment  
be made with respect to indirect meter reading costs.211  
210Greneman, Pre-filed Evidence, Exhibit N-85, pp. 16-17  
211HRM, Redacted Closing Submission, p. 8  
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[595] HRM also asserts that NSPI=s COSS shows that almost $26 million of rate base associated  
with lighting fixtures was assigned to the Unmetered Class, attracting approximately $5.7 million of  
costs for depreciation expense, taxes, interest and return. In HRM=s view, this allocation to rate base  
is a primary reason the Unmetered Class must pay $0.22/KWh, well above other classes.212 Based on  
NSPI=s response to Undertaking U-31, HRM submits that the Unmetered Class has not received any  
credit from NSPI for the new lighting installations contributed by developers and property owners  
over the past ten years. HRM believes that if such contributions were properly credited to the  
Unmetered Class, the rate base assigned to this class would decrease by more than 50%. It estimates  
that such costs comprise approximately $5.7 million or 22.5% of the proposed revenue requirement  
for the Unmetered Class.213 HRM asks the Board to reduce the rate base directly assigned to the  
Unmetered Class to a level of 40% of that currently stated, until a proper assessment of contributions  
is made by NSPI.  
[596] In its Closing Submission, NSPI indicated the following with respect to HRM=s request for a  
review of the C-3 Unmetered Class allocator shown in the COSS:  
NSPI agrees that the study used to develop the C-3 weighting factor for the unmetered class  
should be updated if the factor is to be changed. This would require the acquisition and  
analysis of customer-service-related activity relating to unmetered services over some  
representative period of time. NSPI plans to gather this information by April 1st.  
NSPI also agrees that the study of direct costs for street lights, including installation and  
maintenance costs, requires updating. NSPI plans to complete this work by July 1st.  
(NSPI, Redacted Closing Argument, p. 87)  
212HRM, Redacted Closing Submission, p. 8  
213HRM, Redacted Closing Submission, p. 10  
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11.2.1 Findings  
[597] The Board is satisfied that a study should be conducted to determine whether the present  
weighting factor of 5.0 is still appropriate as the C-3 Unmetered Class allocator. Further, it  
determines that NSPI=s suggested time line is appropriate in the circumstances.  
[598] The Board directs that a cost of service study be conducted by NSPI with respect to the  
Unmetered Class. The study shall include a review of the appropriateness of the current weighting  
factor and a review of the rate base, including assets, assigned to the Unmetered Class. The study  
should indicate a breakdown of costs and rate base by municipality.  
[599] The Board directs that the current weighting factor of 5.0 should remain in effect for the 2006  
test year.  
[600] The cost of service study results shall be filed with the Board by July 31, 2006.  
11.3 Miscellaneous Charges  
[601] NSPI has requested increases to its miscellaneous charges, as outlined in Exhibit N-2,  
Appendix I, along with proposed language changes to certain of its regulations as outlined in Exhibit  
N-2, Appendix J. In keeping with the Board=s direction in the 2005 rate decision, NSPI is limiting  
the proposed increase to the average rate increase for ATL customers.  
[602] The Company submits that the proposed increase to miscellaneous charges brings them closer  
to recovering the actual costs of providing the service. In the four instances where incorporating the  
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average ATL rate increase would have resulted in charges which exceeded the cost to deliver the  
service, the proposed rate increase was capped to reflect the actual cost.214  
[603] As noted in the 2005 rate decision, it is not appropriate for the Company to charge a profit  
margin on miscellaneous charges. NSPI has removed any such mark-up in the present application.  
[604] Ms. Brockway testified that the Board should deny most of the proposed increases to  
miscellaneous charges, particularly since those charges had already been increased considerably in  
2005. In her view, these charges have a significant impact upon low income customers, expressing  
particular concern about the following charges:  
$
$
$
$
$
Regulation 7.1(a), Connection/Reconnection during normal working hours  
Regulation 7.1(b & c), Connection/Reconnection after normal working hours  
Regulation 7.1(e), Collection charge (Doorknob charge)  
Regulation 7.1(e), Collection charge (Registered Letter)  
Regulation 7.1(g), Returned Cheque Charge  
[605] In her Direct Evidence, Ms. Brockway explained the basis for her concern:  
Customers with fixed incomes, seasonal incomes, poverty-level wages, and the like, are  
disproportionately likely to fall into arrears, and be subject to collection practices requiring  
collection actions (doorknob notices, registered letters), and to disconnection, requiring  
reconnection. Indeed, for working poor families, reconnection will usually have to take place  
after hours, or someone will have to take off work at great cost in order to be present during  
the reconnection. Also, with respect to charges intended to prevent Aleaning@on the system,  
they are not likely to have that salutary effect in the case of low-income customers with  
payment difficulties, as these customers will not become better able to pay their bills merely by  
making them higher.  
...  
214NSPI Application, Exhibit N-1, p. 198  
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I recommend that the charges for reconnections, collections and returned cheque charges not  
be increased at this time, but remain as set in the March 2005 order. I recommend that the  
difference in revenues be spread equally to all classes. The impact will be de minimis on  
customers not paying these charges, but will be most welcome for customers with limited  
incomes who are already struggling to keep up with rising energy costs.  
(Brockway, Pre-filed Evidence, Exhibit N-87, pp. 15-16)  
[606] The Consumer Advocate submits that more rigorous standards of Acost recovery@are being  
applied to low income customers than to other classes of ratepayers. In his view, the pursuit of Acost  
recovery@as against low income customers should be carried out with the same exactitude as that  
adopted with respect to the recovery of costs from other ratepayer classes. Describing this  
phenomenon as a type of discrimination, the Consumer Advocate argued:  
68.  
No party would dispute the impact of such charges is particularly onerous for those on  
low incomes and who are the most susceptible of incurring the charges. The only argument in  
favour of the requested increases is that they are needed to recover the costs involved and to  
dissuade customers from defaulting on payments.  
69.  
Yet there can be no doubt that any similar analysis of cost recovery for other rate  
classifications, particularly the AAA rates, would raise questions as to the exact dollar cost  
recovery of the applicable rate. The reality is that precise and undisputed cost recovery is not  
possible and often is explicitly recognized or even intended. The justification is that there must  
be practicality to rate structures. That justification often finds its expression in the concept of  
due discrimination. Whatever it is called, the reality is that many, if not all, rate classifications  
have some degree of uncertainty whether there is perfect cost recovery. Often the inquiry is  
dropped because of the size of the ratepayer and their importance to the maintenance of the  
system.  
70.  
Yet when it comes to recovering the full amount of doorknob notices or returned  
cheques, the pencils are sharpened to ensure the costs are recovered.  
...  
72.  
... While it is not the function of the Board to use rates as an instrument of social  
policy, there is no need to be any more precise in recovering default costs from consumers  
than recovering the costs of service from the various rate classifications.  
(CA, Redacted Closing Submission, pp. 17-18)  
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[607] In its Closing Submission, the Affordable Energy Coalition (AAEC@) reiterated Ms.  
Brockway=s view that there should be no increase to miscellaneous charges, stating that such charges  
have a Adisproportionate impact@on low income customers.215  
215AEC, Redacted Closing Submission, pp. 18-19  
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[608] The AEC urges the Board to adopt Ms. Brockway=s suggestion to spread the shortfall in  
revenues from these charges equally across all classes, stating that this approach will satisfy the  
Board=s obligation to ensure that charges are not unduly discriminatory, as required by s. 67(1) of the  
Public Utilities Act.216 In her evidence, Ms. Brockway testified that spreading the charges in this  
fashion would have a de minimis impact on customers.  
[609] The NDP Caucus submits that individual customers should not be charged for such services  
and that they be absorbed into general operating costs.217  
11.3.1 Findings  
[610] Having reviewed this matter, the Board considers it appropriate to proceed in a manner  
consistent with the approach it adopted in last year=s rate case. Accordingly, the Board approves the  
proposed increases to miscellaneous charges sought by NSPI. As noted above, in the event such  
increases result in a charge which exceeds the cost of delivering the service, the charge must be  
capped at the actual cost.  
11.4 Low Income Consumers  
216AEC, Redacted Closing Submission, p. 19  
217NDP Caucus, Redacted Closing Submission, p. 12  
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[611] The AEC submits that the Board has a statutory obligation to protect the public interest by  
ensuring that the services provided by NSPI are affordable for its customers, including low income  
customers. Referring to the evidence of Mel Boutilier, Executive Director of the Parker Street Food  
and Furniture Bank, and of Joan Jessome, President of the NSGEU, the AEC noted that the impact of  
electricity rates upon low income customers manifests itself in various ways, including homelessness,  
evictions, unsafe heating practices, health problems related to inadequate heating and refrigeration,  
hunger, and other social and housing related problems.218  
[612] The AEC noted that current programs, although helpful, are not adequate to address the needs  
of low income customers. It described a number of these programs, including a program providing  
financial assistance which is administered by the Department of Community Services, relief provided  
by charities and churches, the Keep the Heat Program offered by the provincial government which  
provides heating rebates, and the Good Neighbour Program, which receives approximately $307,000  
through donations from NSPI, its customers and employees.219  
[613] While recognizing that DSM initiatives are important for low income residential customers,  
the AEC adds:  
... Energy efficiency measures alone will not result in electrical services which are affordable to  
all: low income programs must include rate assistance, crisis intervention and improved  
arrears policy and management.  
(AEC, Redacted Closing Submission, p. 3)  
218AEC Redacted Closing Submission, p. 5  
219Undertaking U-13  
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[614] The AEC cites ss. 44 and 67 of the Public Utilities Act in support of its view that the Board  
should develop programs which ensure electrical service is affordable and accessible to all  
consumers:  
45.  
Here, in order for the Board to make a Ajust@order under s. 44, one that avoids a rate  
structure which created effective barriers to equal access for the poor, it is appropriate - and  
Charter compliant - for the Board to order programs to accommodate the disadvantage  
experienced by low-income people.  
46.  
In resolving any ambiguities concerning the scope of the Board=s power to decide on  
the implementation of a Rate Assistance Program, and the correct interpretation of section  
67(1), the Board must avoid interpretations which would have the effect of excluding  
consumers from essential services based on protected grounds, including their socio-  
economic status.  
(AEC, Redacted Closing Submission, pp. 15-16)  
[615] Thus, AEC asserts that the Board must apply the jurisdiction conferred upon it by its enabling  
legislation, in a manner consistent with the equality provisions of the Canadian Charter of Rights  
and Freedoms, in order to ensure non-discriminatory access for low income customers to electricity  
services.  
[616] In its Closing Submission, the Consumer Advocate stated:  
73.  
NSPI made reference several times to giving consideration for low income consumers.  
They are to be commended for identifying that as an objective. Yet apart from the Good  
Neighbour program, for which their contribution is to be commended, there was a lack of any  
specific action, programs or steps relating specifically to low income consumers. All NSPI  
could say was that they would try to ensure that their existing services would be available to  
low income consumers.  
74.  
We ask that the Board in its decision emphasize the importance of developing  
concrete and specific steps directed to the low income consumer.  
(CA, Redacted Closing Submission, para. 73-74)  
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[617] The NDP Caucus also asked the Board to revisit a proposal made by the AEC during the prior  
rate hearing to create a system of supports for low income customers.220  
220NDP Caucus, Redacted Closing Submission, p. 12  
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[618] In its 2005 rate decision, the Board determined that it does not have the statutory authority to  
approve a rate assistance program and that the issue is a Asocial and public policy question which  
falls within the purview of the Legislature rather than the Board.@221  
11.4.1 Findings  
[619] Following the issuance of its 2005 rate decision, Dalhousie Legal Aid appealed the Board=s  
decision. The appeal is set to be heard by the Nova Scotia Court of Appeal. In the circumstances, the  
Board considers it prudent to await the disposition of the appeal before it undertakes any further  
review of the issues raised by the AEC.  
11.5 Pole Attachment Fees  
221Board 2005 Rate Decision, para. 256  
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[620] In its pre-filed evidence, RuSh Communications Ltd. (ARuSh@) expressed concern that some  
of the additional costs projected in OM&G for storm response, vegetation management and storm  
proofing are already being recovered in the rates charged to telecommunications clients such as  
RuSh. It asserts that costs for storm response, vegetation management and storm proofing are already  
included in NSPI=s pole attachment rate of $14.15 and its incremental Amake-ready@charges for  
vegetation management and general maintenance on structures accessed by tenants like RuSh to  
upgrade their equipment.222  
[621] NSPI denies the assertions made by RuSh. It notes that the revenues received from pole  
attachment fees and Amake-ready@charges are separately accounted for in the revenue requirement  
for the 2006 test year. It further notes that the $14.15 pole attachment fee only covers capital  
recovery, routine general maintenance and vegetation management, while additional construction or  
plant upgrade costs are recovered in Amake-ready@charges.223  
222RuSh Communications, Pre-filed Evidence, Exhibit N-86  
223NSPI, Rebuttal Evidence, Exhibit N-153, pp. 108-109  
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11.5.1 Findings  
[622] The Board concurs with NSPI=s position on this issue. The setting of the pole attachment fee,  
as well as the scope of costs recovered under that rate and under Amake-ready@ charges, were  
canvassed by the Board in its Decision on such issues dated January 24, 2002. The Board is satisfied  
that NSPI=s allocation of costs is in accord with that Decision and that the Company=s proposed rate  
increase does not result in a duplication of the revenue earned from pole attachment fees and Amake-  
ready@charges.  
11.6 Renewable and Environmentally Sustainable Energy  
[623] Some of the intervenors asked the Board to consider environmental issues in assessing  
NSPI=s application for a rate increase.  
[624] In its Closing Submission, the Ecology Action Centre submitted that energy issues are  
Ainherently environmental issues@. In its view, a rate increase is only justified if the resulting  
increase in revenues is directed towards making energy production, distribution, and consumption  
environmentally sustainable. According to the EAC:  
... The EAC maintains that energy security for Nova Scotia residents would be best provided  
by including a combination of more aggressive and practical Demand Side Management  
(DSM) programs and greater encouragement of the development of clean and sustainable  
energy sources for Nova Scotia.  
The EAC believes that NSPI must focus on a sustainable, long term vision for electrical energy  
production and distribution in Nova Scotia. The EAC asserts that, as it is now designed,  
NSPI=s current rate application simply prolongs Nova Scotia=s reliance on coal and other  
fossil fuels to produce electricity.  
(EAC, Redacted Closing Submission, p. 1)  
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[625] In addition to submissions respecting DSM, the EAC made a number of recommendations  
related specifically to renewable and environmentally sustainable energy, including:  
2)  
That NSPI develop a more ambitious strategy to reduce green house gases (GHGs)  
and pollution through renewable energy generation programs, internal NSPI DSM  
initiatives, and more extensive DSM services for customers in all rate classes.  
...  
3)  
That all coal and natural gas plants in Nova Scotia be retrofitted to reduce air pollution  
and waste energy. This includes the fitting of scrubbers at all thermal generating  
stations that remain in service, the deactivation of sites that cannot be fitted with  
pollution controls in a cost effective manner, and the installation of systems to recover  
waste heat.  
...  
4)  
That NSPI amend its Renewable Portfolio Standard (RPS) and increase its  
commitment to green energy production by increasing the minimum amount of total  
energy production to come from new renewable sources from five percent by the year  
2010 to ten percent by 2010[sic] and twenty percent by 2015.  
...  
5)  
6)  
8)  
That the UARB support the use of standard offer contracts to encourage the  
development of local renewable energy production initiatives, and that the conditions  
and price paid be determined by the UARB.  
...  
That the UARB consider in its rate case ruling the introduction of a systems benefit  
charge to facilitate funding of DSM and renewable energy initiatives administered by  
an independent agency.  
...  
That an independent study be conducted to investigate alternative rate designs for the  
purpose of developing a rate structure for Nova Scotia which most appropriately  
furthers economic and environmental sustainability. The EAC is interested in the idea  
of implementing an inverted block rate in all classes, coupled with strong DSM  
initiatives.  
(EAC, Redacted Closing Submission, pp. 2-6)  
[626] In its Closing Submission, the NDP Caucus echoed the EAC=s concerns about NSPI=s  
reliance on fossil fuels:  
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The utility=s vulnerability to the fluctuating prices of imported fuel has created a new urgency  
for increased energy security through the use of domestic, renewable energy generation. It is  
our view that the Board should note where legislative or policy changes by government would  
help to achieve this objective.  
(NDP, Redacted Closing Submission, p. 14)  
11.6.1 Findings  
[627] The Board notes from its review of the evidence that NSPI has undertaken steps to address  
many of the issues raised by the EAC, including significant stakeholder consultation with respect to  
DSM, targeting increased sources of renewable energy such as wind from independent producers, and  
retrofitting its generation facilities to reduce air pollution and waste energy.  
[628] In the Board=s opinion, NSPI has undertaken concrete steps to address many of the concerns  
raised by the EAC, the NDP Caucus, GPI Atlantic and ECANS. While much work remains to be  
done, the Board is satisfied that NSPI is addressing these issues. The Board will continue to monitor  
the Company=s progress. It should be noted that DSM and air emission controls will be the subject  
of separate hearings held by the Board in 2006.  
11.7 Incentive Compensation Plan Review  
[629] In its March 31, 2005 rate decision, the Board determined that NSPI=s incentive  
compensation plan should be reviewed to determine whether it delivers an equal benefit to both  
shareholders and ratepayers, who now share the cost of the plan on a 50/50 basis. The Board directed  
NSPI to file a report within six months of its decision, such plan to be then reviewed by independent  
experts engaged by the Board.224  
224Board Decision, March 31, 2005, para. 346  
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[630] NSPI=s Incentive Compensation Report was filed with the Board on September 30, 2005. In  
response to NSDOE IR-91, the report was filed in this hearing.  
[631] Avon submits that NSPI=s Report is unresponsive to concerns raised by intervenors during  
the last rate case, in that the Company, according to Avon, has provided little more than a  
generalization of the benefits accruing to customers. Avon=s concern is that the executive incentive  
plan is not sufficiently aligned with ratepayers=interests (i.e., at least not to the extent of 50%). In  
support of this concern, Avon refers, as an example, to the Abalanced scorecard@for NSPI=s Director  
of Energy Fuels and Risk Management, which was the subject of cross-examination during the  
hearing.225  
[632] In light of its concerns, and the Board=s directives arising out of the last rate decision, Avon  
notes that NSPI is forecasting to double the bonuses paid out in 2006 over those paid in 2005, with  
50% of the maximum possible bonus award for 2006 being included in costs for the 2006 test year.226  
Avon questions whether such bonuses should be awarded in the context of NSPI=s request for a  
significant rate increase for customers. It adds that the burden is on NSPI to demonstrate that these  
expenses are reasonable and prudently incurred.  
225Avon, Redacted Rebuttal Submission, pp. 17-18; Transcript, November 17, 2005, pp. 841-847  
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11.7.1 Findings  
[633] The Board has engaged Lawrence N. Koppelman of Liberty to review NSPI=s Incentive  
Compensation Report. His report was recently filed with the Board and has been forwarded to NSPI  
for their comment. Any issues arising from this review can be addressed in a future rate hearing. For  
the 2006 test year, the Board approves the amounts proposed by NSPI.  
11.8 Non-Profit Intervenor Costs  
[634] The Affordable Energy Coalition asks the Board for costs in this matter. In support of this  
request, it stated:  
73.  
The Affordable Energy Coalition is a non-profit coalition of individuals and groups who  
work directly with low income Nova Scotians. These groups combined their efforts in a  
manner consistent with previous rulings of this Board, which had the effect of reducing hearing  
time and other costs.  
...  
75.  
Each of the members of the AEC is a non profit organization, and has no commercial  
interest in the outcome of these hearings. None of these groups receive funding to support  
public interest litigation or the costs of intervention in this rate application.  
...  
77.  
Low income Nova Scotians have a substantial interest in the application to increase  
rates by NSPI. The effect of a rate increase on low income residential consumers will be  
immediate and far ranging as it deepens already unsustainable energy burdens on this group  
of consumers.  
226Avon IR-9(d)-(f)  
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78.  
It is submitted that the AEC acted responsibly and prudently in these hearings. The  
intervention on behalf of low income consumers combined the interests of several groups and  
it consciously avoided duplicating the evidence already presented or made available by other  
interveners in the matter. As such, it is submitted that the AEC has behaved in a responsible  
manner to incur only such costs as were necessary to complete the evidence before the Board  
concerning the issues in this application.  
79.  
It is submitted that the arguments submitted by the AEC have contributed to the  
Abetter understanding@ of the issues affecting low income residential customers in this  
application for a rate increase by NSPI.  
(AEC, Redacted Closing Submission, pp. 23-24)  
11.8.1 Findings  
[635] NSPI has not addressed the AEC=s request for costs in its submissions. The Board directs  
NSPI to file its response to this request no later than April 20, 2006. AEC will have an opportunity to  
file additional written submissions on this issue no later than May 1, 2006. Following its review of  
the submissions, the Board will issue a ruling on this request.  
11.9 General Demand Rate Class  
[636] Robert Cook, President of the Nova Scotia Association of Health Organizations (ANSAHO@),  
made a presentation to the Board at the evening session on November 23, 2005. He outlined the  
mandate of his association and stated that it represents and provides services to the health  
organizations in the Province. The types of organizations NSAHO represents include hospitals,  
nursing homes, group homes, adult residential centres and home care support entities.  
[637] Mr. Cook stated that NSAHO=s reason for appearing at the hearing was the significant  
proposed rate increases, and the revenue/cost ratio (AR/C@) for the General Demand class. He stated  
that the current R/C ratio for the General Demand customers is 108.75%, which is outside the  
Board=s target range of 95% to 105% for all customers. He outlined the impact this higher R/C ratio  
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is having on NSAHO=s members, based on the total current annual bill of approximately $20 million  
for these customers. He also pointed out that the R/C ratio for the General Demand class has been  
above 105% for some time and is causing hardship to NSAHO=s members.  
11.9.1 Findings  
[638] In the Board=s view, as set out in its 2002 and 2005 rate decisions, it is desirable to maintain,  
where reasonable, an R/C ratio between 95% and 105% for all classes. The Board continues to  
believe that it is fair and reasonable, in terms of the impact on other ATL customers, for the General  
Demand class to be gradually moved to an R/C ratio of 95% to 105%.  
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12.0 SUMMARY OF DISALLOWANCES AND ADJUSTMENTS  
[639] NSPI, in its July 5, 2005 filing, projected a revenue requirement for 2006 of $1,003.7 million  
from above-the-line customers, which was $128.4 million higher than the 2005 Compliance Filing.  
[640] NSPI illustrates the increases sought from customers, including the resulting revenue cost  
(AR/C@) ratios and the total revenue requirement in the following table compiled by the Board:  
2006 Rate Application - July 5, 2005  
Current  
Revenue  
Proposed  
Revenues  
Revenue  
Increase  
Revenue %  
Increase  
R/C  
Ratios  
Costs  
ABOVE-THE-LINE CLASSES  
Residential  
Total Residential  
$435.2  
$512.6  
$504.3  
$69.1  
15.9%  
98.4%  
Commercial  
$25.9  
$224.8  
$30.2  
$29.4  
$237.2  
$36.0  
$30.1  
$249.0  
$35.0  
$4.2  
$24.2  
$4.8  
15.9%  
10.8%  
15.9%  
11.8%  
102.3%  
105.0%  
97.3%  
Small General  
General Demand  
Large General  
Total Commercial  
$281.0  
$302.6  
$314.2  
$33.2  
103.8%  
Industrial  
$20.7  
$43.2  
$59.9  
$23.5  
$49.7  
$73.9  
$24.0  
$50.1  
$70.2  
$3.3  
$6.9  
$10.3  
$20.5  
15.9%  
15.9%  
17.2%  
16.5%  
102.2%  
100.8%  
95.0%  
98.1%  
Small Industrial  
Medium Industrial  
Large Industrial  
Total Industrial  
$123.8  
$147.1  
$144.3  
Other  
$13.4  
$21.9  
$35.3  
$16.3  
$25.1  
$41.4  
$15.5  
$25.4  
$40.9  
$2.1  
$3.5  
$5.6  
15.9%  
15.9%  
15.9%  
95.4%  
100.9%  
98.8%  
Municipal  
Unmetered  
Total Other  
Total A/L Classes  
Total B/L Classes  
Total All Classes  
$875.3  
$1,003.7  
$1,003.7  
$146.4  
$128.4  
14.7%  
100.0%  
$1,150.1  
Exports  
$8.3  
Miscellaneous  
$10.4  
Total Revenue  
Requirement  
$1,168.8  
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[641]  
As the Board has outlined in this decision, a number of disallowances and adjustments  
have been made which reduce NSPI=s 2006 revenue requirement. These are set out below:  
Disallowances and Adjustments  
ITEM  
Imprudence disallowance - fuel costs  
Additional natural gas resale benefit  
PTMT - fuel disallowance  
DISALLOWANCES/ ADJUSTMENTS  
$15,700,000  
$35,800,000***  
$2,300,000  
OM&G  
$12,300,000  
Load Reduction  
$1,600,000  
Cash working capital (Rate Base)  
Long-term receivable (Rate Base)  
Total Disallowances and Adjustments  
$1,400,000*  
($1,186,000)**  
$67,914,000  
*($29,400,000 - 12,250,000) x 8.21% WACC = 1,408,000  
**Average increase in rate base of 14,450,000 x 8.21% WACC = 1,186,000  
***NSPI proposed an additional natural gas resale benefit of $22.6 million as the estimated impact of the  
settlement with its supplier  
[642] The Board understands that the $67.914 million in disallowances and adjustments listed  
above are estimates based on the evidence filed during the hearing. The Board directs NSPI,  
through the Compliance Filing, to confirm the actual reduction in revenue requirement which flows  
from this decision.  
[643] As noted earlier, NSPI originally requested an increase in its revenue requirement of  
approximately $128.4 million from ATL customers. This request resulted in a proposed average  
increase for ATL customers of 14.7%, with an average increase of 15.9% for domestic customers.  
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NSPI later indicated that the proposed increase would be reduced by about 2% due to the settlement  
with its natural gas supplier, announced November 21, 2005.  
[644] The disallowances and adjustments directed by the Board and noted above, are expected to  
result in an approximate average rate increase of 8.6% for above-the-line customers. Domestic  
customers can expect a rate increase of approximately 8.9%. The increase in rates for ATL  
customers is effective March 10, 2006. The ELIIR and 2P-RTP rate shall be determined by NSPI in  
the Compliance Filing as set out in this decision. All other below-the-line rates are approved as set  
out in this decision. All BTL rates are effective January 1, 2006.  
[645] As noted in prior rate decisions, the Board considers it desirable to maintain, where  
reasonable, an R/C ratio of 95% to 105%. The Board recognizes that the General Demand class  
category did not fall within the 95% to 105% R/C range in 2005, but it determined in its decision  
that it is fair and reasonable, in terms of the impact on other ATL customers, for this rate group to be  
gradually moved within the 95% to 105% R/C ratio. The Board continues to believe that the  
General Demand class should gradually be moved to an R/C ratio of 95% to 105%.  
[646] The Board directs NSPI to base its adjustments in the Compliance Filing on the findings  
noted above.  
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13.0 FINANCIAL HEALTH OF NSPI  
13.1 Submissions - NSPI  
[647] In its evidence and submissions, NSPI repeatedly urged the Board to consider the financial  
health of the Company in assessing the rate application. In its Opening Statement, the Finance Panel  
cautioned that NSPI=s customers would ultimately suffer from a possible credit rating downgrade  
faced by the Company:  
As the Board is aware from information provided directly and as part of this hearing, Nova  
Scotia Power is facing the very real prospect of a credit rating downgrade in the near future  
should the Company not be able to recover its fuel costs and improve its cash flow position. If  
these circumstances were not addressed, this would be a very significant event for the future  
of Nova Scotia Power with long-term implications for our customers. The Company is  
experiencing cash flow shortages today that are not sustainable if the Company is to continue  
as a financially viable utility.  
As a regulated investor-owned utility, we have a responsibility to both our customers and our  
shareholders. The continued financial strength of the utility is important to both parties. In the  
long run it is most important to our customers.  
Investors have choices about where to invest money. If NSPI is not viewed as providing a fair  
return compared to other utilities, NSPI will be limited in its access to capital. This would  
ultimately lead to higher costs, and in a worse case, inability to access fuel markets and  
provide appropriate customer service. It is our customers who would ultimately bear the brunt  
of a credit rating downgrade.  
(Exhibit N-170)  
[648] This issue was further highlighted by Mr. Huskilson near the conclusion of the hearing:  
... A year ago no one had anticipated such increases in world fuel prices or in that volatility.  
This creates a much greater risk for both us and for our customers, and uncertainty for all of  
us. Nova Scotia Power has paid a heavy penalty Bperhaps heavier than anticipated -- for  
past actions, and I believe that a second fuel cost disallowance would create a very high risk  
that Nova Scotia Power would see its credit rating downgraded. That's certainly not in the  
best interests of customer because, you see, our customers are expecting us to invest in their  
energy future and that will require millions of dollars of future capital.  
(Transcript, December 1, 2005, p. 3052)  
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[649] NSPI indicates that its financial health has deteriorated, leading two of the three rating  
agencies that rate NSPI (Standard & Poor=s and Moody=s) to lower their outlook on NSPI from  
Astable@to Anegative@.227 The Company cautions that it risks a rating downgrade, observing that it  
would become the lowest-rated electric utility in Canada if it is downgraded one more notch by  
Standard & Poor=s. According to Moody=s, there are various factors which could lead to a  
downward rating, including the Company=s inability to maintain sustainable credit metrics, its  
failure to receive timely and balanced regulatory decisions, its inability to manage its fuel price risk,  
and its increased reliance on short-term or floating rate debt.228  
[650] In its evidence, NSPI referred the Board to various examples of comments provided by rating  
agencies about the financial health of the Company:  
The negative outlook reflects the weakening of the companies= financial profiles due to  
NSP=s inability to fully recover its fuel costs through rate increases. The negative outlook  
also reflects Moody=s concern that there may not be the regulatory willingness to address  
NSP=s fuel price risk exposure through periodic rate applications or the adoption of a fuel  
price pass-through mechanism. Moody=s also expects that increasing capital expenditure  
requirements over the medium term will cause NSP to have a negative trend for free cash  
flow over the next few years.  
(Moody=s Investor Services, Global Credit Research Credit  
Opinion: Emera Inc., October 11, 2005; NSPI, Redacted  
Closing Argument, p. 52)  
[651] Similar concerns were expressed even after NSPI reached a settlement with its supplier  
respecting its long-term natural gas agreement:  
227NSPI, Rebuttal Evidence, Exhibit N-153, pp. 54-55; Province IR-70 (Supplemental)  
228Province IR-70 (Supplemental)  
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Both Emera=s and NSPI=s financial profiles have been weakened by, among other things,  
under-recovery of increasing fuel costs at NSPI. Significant uncertainty remains regarding  
the timeliness and fullness of future fuel cost recovery. Yesterday=s announced gas pricing  
arrangement, therefore, will not serve to strengthen the utility=s financial profits. Meaningful  
improvement in the company=s business and financial profiles is reliant on favourable  
regulatory decisions in 2006.  
(Standard & Poor=s, Bulletin, November 22, 2005, Exhibit  
N-221; NSPI, Redacted Closing Argument, p. 52)  
[652] NSPI stresses the need for the Company to maintain an ability to secure capital investment  
for future projects. In its Closing Argument, it quoted Bonbright in support of this view:  
Professor Bonbright identifies the Capital-Attraction Standard as Aone of the most prominent  
and most widely recognized functions of public utility rates@:  
By this standard, reasonable rates are rates adequate to yield revenues that  
will cover all legitimate operating expenses plus a return on investment  
sufficient to maintain sound corporate credit and to attract required  
amounts of new capital. Rates below this level are deemed inefficient  
because, at least in the long run, they will not enable the company to  
live up to its obligation to service the community. [Emphasis added in  
original]  
(NSPI, Redacted Closing Argument, p. 51)  
[653] NSPI submits that a rating downgrade will have serious consequences for the Company,  
including higher borrowing and capital costs over the long-term as the Company refinances debt and  
attempts to raise new capital to support capital investment in facilities. Moreover, NSPI states that  
the most immediate impact of a credit downgrade will be its impact upon fuel procurement  
procedures and costs. It notes that a credit downgrade will impact credit limits with suppliers,  
impose less flexible payment terms, require deposits or up-front payments, raise borrowing costs,  
increase fuel costs and, possibly, result in the inability to obtain fuel from certain suppliers.229  
229NSPI, Redacted Closing Argument, pp. 54-55  
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[654] Despite the assertion by intervenors that the risk of a downgrade must not deter the Board  
from denying costs which are not reasonably incurred, Mr. Huskilson underscored that the impact of  
any credit downgrade would ultimately be borne by NSPI=s customers:  
A.  
(Huskilson) Well, if you're talking about bond ratings, it ultimately is an issue that the  
company has and also an issue for customers. And the reason that it's an issue for  
customers is because customers expect the company to make investments. And as  
the company makes investments, it has to raise money. And if it's unable to raise the  
money necessary to make those investments, then that will affect service. And that's  
the kind of thing that whether the -- it's very hard to separate the stakeholders of a  
company like a utility because, ultimately, all the stakeholders of the utility need the  
utility to be in a healthy situation and to be able to perform the functions and the  
service that it needs to provide.  
(Transcript, December 1, 2005, pp. 3198-3199)  
13.2 Submissions - Intervenors  
[655] A number of the intervenors questioned NSPI=s assertion that the Company=s financial  
health is in jeopardy. SEB refers to the evidence of Dr. Rosenberg, who disputes NSPI=s claim that  
it is not financially healthy. After adjusting for the $18 million fuel disallowance incurred in the  
2005 rate case, Dr. Rosenberg maintains that NSPI will still earn a return on equity of 9.36%, which  
is within the approved ROE band. This assertion was challenged by NSPI, which stated that the  
actual ROE for 2005 is expected to be 8.58%.  
[656] In addition to Dr. Rosenberg=s relatively optimistic view with respect to NSPI=s 2005 ROE  
performance, Avon refers to other items which could potentially add to NSPI=s 2005 earnings,  
including the Company=s settlement with its natural gas supplier, the Company=s receipt of a  
favourable court order issuing an attachment order with respect to its litigation with AMCI Traders  
respecting a claim of $11.2 million, and a $5 million saving from the 2005 Compliance Filing for  
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interest expense as a result of the Company=s ability to secure lower interest rates in issuing long-  
term debt.230  
13.3 Findings  
[657] The Board recognizes the importance of ensuring that NSPI remain on a sound financial  
foundation as it heads into the future. The Company=s ability to attract capital, access fuel markets  
and control costs must not be compromised.  
[658] In the view of the Board, there are various reasons to be confident about NSPI=s future  
financial health. First, with respect to fuel, which is the most significant component of costs, the  
Board has approved what it considers to be an appropriate estimate of total fuel costs. The Board  
recognizes, of course, that any estimate of future costs is subject to error. However, based on the  
most current information available at the time of the hearing, there is reason to be confident that  
NSPI can meet the approved fuel budget, and perhaps even better it.  
[659] The only material exception to the Company recovering its fuel costs in 2006 is the  
imprudence disallowance of $15,700,000. Since NSPI essentially enjoys the benefit of being a  
monopoly supplier of electricity in this Province, it is imperative that it only be able to recover its  
prudently incurred costs. Ratemaking principles and utility regulation require that costs incurred  
imprudently should not be borne by ratepayers.  
230Avon, Redacted Closing Submission, pp. 23-24  
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[660] Having said that, the Board wishes to emphasize that the imprudence finding for the failings  
discussed in this decision will no longer have an impact upon NSPI=s fuel budget. The Board is  
satisfied that NSPI has taken significant steps to improve its fuel procurement policies, incorporating  
a portfolio approach which will help dampen the impact of price volatility. This will allow NSPI to  
better achieve results falling within the parameters of its fuel budget, which is reflected in rates.  
[661] While certain OM&G expenses have not been approved by the Board, it notes that the costs  
which were denied will not generally impair NSPI=s existing operations, but, instead, will merely  
curtail the spending with respect to programs requested by NSPI (e.g., DSM, vegetation  
management, communications). A further result of this rate case is the Board=s direction that an  
operations review of NSPI must be carried out. This review will critically examine NSPI=s  
operations and help ensure the efficient allocation of its resources. This should ultimately yield  
positive results for NSPI customers and investors alike.  
[662] The Board recognizes that the interests of customers and shareholders of NSPI are not  
mutually exclusive. They both benefit from a financially sound utility. In this decision, the Board  
has strived to strike an appropriate balance between the interests of NSPI and its customers.  
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14.0 SUMMARY OF BOARD FINDINGS  
14.1 Financial Health of NSPI  
[663] In its evidence and submissions, NSPI repeatedly urged the Board to consider the financial  
health of the Company in assessing the rate application. NSPI indicates that its financial health has  
deteriorated, leading two of the three rating agencies that rate NSPI (Standard & Poor=s and  
Moody=s) to lower their outlook on NSPI from Astable@to Anegative@. The Company cautions that  
it risks a rating downgrade.  
[664] NSPI submits that a rating downgrade will have serious consequences for the Company,  
including higher borrowing and capital costs over the long-term as the Company refinances debt and  
attempts to raise new capital to support capital investment in facilities. Moreover, NSPI states that  
the most immediate impact of a credit downgrade will be its impact upon fuel procurement  
procedures and costs. It notes that a credit downgrade will impact credit limits with suppliers,  
impose less flexible payment terms, require deposits or up-front payments, raise borrowing costs,  
increase fuel costs and, possibly, result in the inability to obtain fuel from certain suppliers.  
[665] The Board understands the importance of ensuring that NSPI remain on a sound financial  
foundation as it heads into the future. The Company=s ability to attract capital, access fuel markets  
and control costs must not be compromised.  
[666] The Board recognizes that the interests of customers and shareholders of NSPI are not  
mutually exclusive. They both benefit from a financially sound utility. In this decision, the Board  
has strived to strike an appropriate balance between the interests of NSPI and its customers.  
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14.2 Fuel Procurement Strategy  
[667] The Board recognizes the effort expended by NSPI in implementing many improvements in  
its fuel procurement procedures, and in the Fuel Procurement Policies and Procedures Manual, in the  
relatively short period of time which has elapsed since the Board=s 2005 rate decision.  
[668] However, a number of deficiencies still remain. The Board directs that NSPI implement, as  
soon as possible, all the recommendations by Liberty set out in this decision, and that NSPI file a  
report by August 31, 2006, outlining the status of the recommendations which were implemented,  
and those recommendations, if any, which were not implemented. The Board further directs that  
NSPI liaise with Liberty in the implementation of these recommendations.  
[669] Notwithstanding that the Manual is not finalized and has not received approval, NSPI must  
proceed with the implementation of its proposed fuel strategy. The Board expects NSPI to use its  
judgment both with respect to the changes it proposes to the Manual, and with respect to the  
implementation of the fuel strategy.  
[670] In its March 31, 2005 decision, the Board directed NSPI to engage a fuel procurement expert  
with respect to coal acquisition. While the Board understands that NSPI has been diligently working  
to identify and employ such an individual, the Board wishes to convey to NSPI its concern over the  
lack of progress in this very significant area of NSPI=s operations. Accordingly, the Board directs  
NSPI to continue expeditiously with its efforts to obtain a solid fuel expert. Failing that, NSPI is  
directed to consider and evaluate other options which would permit it to acquire the necessary skills  
to enable it to acquire coal on a competitive basis in the international market. NSPI is directed to  
file a quarterly status report with the Board concerning this matter, commencing April 30, 2006.  
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14.3 Carryover of Imprudency  
[671] The Board concludes that there is a continuing harm in 2006 as a result of NSPI=s failure to  
implement a portfolio strategy commencing in 2002. The Board is satisfied that, for the same  
reasons as the Board found in its decision of March 31, 2005, NSPI had an opportunity at that time  
to begin implementing an appropriate fuel procurement strategy. If NSPI had taken advantage of  
that opportunity, as it should have done, it would have been able to obtain coal for 2006 at costs  
significantly less than those which it now forecasts for the 2006 test year. The additional expense  
involved should not be borne by the ratepayers because it was imprudently incurred. The Board sets  
the imprudence disallowance for the 2006 test year at $15,700,000.  
[672] To avoid any uncertainty going forward, the Board wishes to make it clear that the impact of  
NSPI=s past imprudence for the failings discussed in this decision is now spent and will not extend  
beyond the 2006 test year. This is because, even if NSPI had entered into a multi-year contract in  
2002 and 2003, as the Board considers it should have done, the Board is satisfied that such contract  
would have likely run its course by the end of 2006.  
14.4 Long-Term Contract  
[673] In April of 2005, NSPI entered into its first multi-year contract to acquire low sulphur import  
coal. The Board finds that the April 2005 contract was not an imprudent transaction.  
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14.5 Affiliate Activity  
[674] The Board is not prepared at this time to require NSPI to assume direct responsibility for  
selling its surplus natural gas. However, the Board will monitor the transactions and the relationship  
between NSPI and the company selected to handle NSPI=s natural gas, particularly if the  
arrangement should be with an affiliated company.  
[675] The Board directs that NSPI conduct a study to determine the feasibility of establishing an  
in-house capability to sell its own gas. The study shall be filed with the Board by August 31, 2006.  
[676] The Board accepts the recommendation of Liberty to implement a process of detailed,  
periodic audits of affiliate transactions. Due to Liberty=s extensive knowledge of NSPI, the Board  
will retain Liberty to carry out the first audit. During 2006, the Board will request Liberty to prepare  
a detailed work plan for the first audit, including the estimated time and budget, as well as an  
appropriate commencement date. The Board directs that the work plan be filed with the Board by  
June 30, 2006 for Board approval. NSPI will be consulted during this process and its opinions  
solicited. The Board, in planning the commencement date for the first audit, will give consideration  
to other time commitments which may be facing NSPI.  
[677] The detailed audit of affiliate transactions is not meant to replace the annual reporting  
required under the Code of Conduct.  
14.6 Point Tupper Marine Terminal  
[678] The Board has determined that NSPI is not entitled to include, in its fuel expense, a capital  
recovery charge of $2.3 million with respect to the Point Tupper Marine Terminal.  
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[679] At a future date, NSPI may apply to have the PTMT included in rate base. Should NSPI  
make such an application, the Board is prepared to consider at that time whether an allowance  
should be made for deferred capital charges.  
14.7 Natural Gas Resale Benefit  
[680] During the hearing, NSPI announced it had reached a settlement with its supplier on  
the future pricing and supply arrangements of natural gas. As a result of the settlement,  
the Company expects to achieve better results on the resale of its natural gas than  
originally forecast when it filed its application on July 5, 2005. The Board finds that it is  
reasonable to adopt a gas resale benefit of $35.8 million higher than that contained in the  
original filing of July 5, 2005, thereby decreasing NSPI=s original fuel budget by the same  
amount.  
[681] The Board determines that no deferral mechanism or reserve fund should be implemented at  
this time. In a test year where customers are facing a significant rate increase, the Board is loath to  
defer any potential benefits from the gas resale benefit to a future test year.  
[682] Some intervenors asked the Board to consider whether the benefits of the natural gas  
settlement between NSPI and its supplier were appropriately allocated between the Company=s  
customers and shareholders.  
[683] Having reviewed the terms of the negotiated settlement, the testimony related to it, and the  
submissions of the parties, the Board is persuaded that the settlement reached with the supplier  
benefits NSPI=s customers and that there was a fair and reasonable allocation of the benefits  
accruing under the settlement between shareholders and customers.  
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14.8 Fuel Costs  
[684] With the exception of the items noted above, the Board is of the view that there should be no  
further adjustment to NSPI=s fuel budget. The Board sets NSPI=s fuel budget for the test year at  
$425,100,000.  
14.9 Return on Equity  
[685] In the 2005 rate decision, the Board approved a return on equity at 9.55% for the purpose of  
setting rates, with an earnings range set at 9.30% to 9.80%. The Board has made no change to return  
on equity.  
14.10 Capital Structure  
[686] In the 2005 rate decision, the Board approved an increase in the common equity ratio for  
ratemaking purposes from 35% to 37.5%. The Board is satisfied that the common equity ratio  
should be maintained at 37.5%.  
14.11 Rate Base  
[687] In the 2005 rate decision, the Board directed that NSPI use a return on rate base methodology  
for its next rate application. The main issue which arose from the adoption of this approach was  
calculating the cash working capital (ACWC@) allowance.  
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[688] While the Board determined that HST should be included in the calculation of the CWC  
allowance, it has excluded other items like the securitization of accounts receivable, interest expense  
and preferred dividends. The Board has also made adjustments to some of the lead/lag assumptions  
to be incorporated into the calculation.  
[689] Based on the above findings, the Board has set the CWC allowance for the 2006 test year at  
$12.25 million, which has the effect of reducing the rate base by $17.15 million ($1.4 million  
reduction in the revenue requirement).  
[690] The only other adjustment to rate base which appears to be justified on the evidence is to  
account for the increase in the long-term receivable resulting from the settlement between NSPI and  
its natural gas supplier. The Board approves an increase in the rate base of $14.45 million to reflect  
the difference between the long-term receivable estimated in the original rate filing and the amount  
estimated following the settlement.  
[691] The amount of the 2005 Q1 tax deferral has not been finally determined as yet and, in the  
Board=s view, it would be premature to include any amount in rate base at this time.  
14.12 Operating, Maintenance and General Expenses (OM&G)  
[692] The Board approves an increase in Operating, Maintenance and General expenses from  
$182.0 million (2005C) to $197.5 million for the 2006 test year, a $15.5 million increase. NSPI had  
requested an increase of $27.8 million.  
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(a)  
Power Production  
[693] All the proposed Power Production increases are approved except a disallowance relating to  
succession planning. In the view of the Board, an additional amount of $1.0 million per year (rather  
than $1.8 million) should adequately address this group=s succession planning issues for the 2006  
test year.  
(b)  
Customer Operations  
[694] With respect to Customer Operations, the Board approves a proposed cost increase for  
enhanced storm response, which reflects an increase from $1.4 million presently included in rates to  
$5.4 million allocated for the 2006 test year. The Board is mindful that NSPI has greatly enhanced  
its storm response activities since major storm events like Hurricane Juan and the November 2004  
storm.  
[695] The Board has reduced NSPI=s proposed increase respecting succession planning for power  
line technicians from $500,000 to $300,000.  
[696] In relation to vegetation management, NSPI requested an increase from $5.2 million to  
$10.4 million in spending. The Board approves a total of $6.8 million ($3.2 million for the  
transmission system and $3.6 million for the distribution system), an increase of $1.6 million over  
the amount currently reflected in rates.  
[697] NSPI has also requested an additional $1.3 million to improve communication with its  
customers. The Board approves the requested amount of $500,000 with respect to enhancements to  
the HVCA and IVR telephone systems, as well as the testing of the systems. However, the Board is  
not satisfied that NSPI=s request for the remaining $800,000 is warranted particularly in the context  
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of the significant rate increase being requested by the Company. It reduces from $800,000 to  
$300,000, the amount requested with respect to increased customer research, additional proactive  
communications and increased quality assurance in the customer service area.  
(c)  
Corporate Support Group  
[698] With respect to the Corporate Support Group (with the exception of DSM which is discussed  
below), the Board denies the Company=s request for a $492,000 increase for advertising activities  
carried out by the Investor and External Relations group. It is the view of the Board that such  
expenses related to promoting the Company=s corporate image and enhancing its goodwill in the  
community should not be included in the revenue requirement being sought from customers.  
[699] The Board approves the $1.6 million expenditure increase under Regulatory Affairs  
respecting a 2007 rate case which NSPI expects to file in 2006, as well as the $400,000 increase for  
the 2006 Board assessment.  
[700] New governance and audit regulations adopted by the OSC will result in higher regulatory  
compliance costs. The Board directs that half of the proposed net increase be deferred to 2007,  
resulting in a net increase approved for this activity of $235,000 ($470,000 less 50% recovered from  
Emera).  
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(d)  
Corporate Adjustments  
[701] With respect to Corporate Adjustments, the Board denies NSPI=s proposed deferral of $2.0  
million associated with regulatory expenses incurred by the Company in 2005, including the cost of  
the rate hearing held in 2005 and the increased 2005 Board assessment. In the Board=s opinion, it is  
not reasonable to burden ratepayers with the cost of two rate hearings and two increased Board  
assessments in the same test year, which would be the case were the Board to permit NSPI to roll the  
2005 costs into 2006.  
[702] The Board approves the remainder of the Corporate Adjustments sought by NSPI, including  
an increase relating to pension expense from $26.0 million to $31.7 million for the 2006 test year.  
This represents an increase of $5.7 million in pension expense, which was supported by an actuarial  
report outlining the basis for this increase.  
14.13 Operations Review  
[703] In past decisions, the Board has expressed concern about the control of OM&G expenses by  
NSPI. Following its review of the evidence in this hearing, the Board continues to be concerned  
about the magnitude of the increase sought by NSPI for OM&G expenses, particularly since it  
accompanies NSPI=s request for a very significant rate increase.  
[704] Accordingly, the Board directs that an operations review be carried out on NSPI=s  
operations. The review shall encompass a detailed examination of NSPI=s organizational structure,  
its level of OM&G expenditures, and any other pertinent areas which may come to light, with a view  
to determining whether cost savings and operational efficiencies can be achieved. NSPI is directed  
to prepare the terms of reference for the operations review and submit them to the Board for  
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approval by May 31, 2006. The terms of reference shall also set out the procedures for identifying  
and selecting the firm or person who will perform the operations review.  
[705] The Board directs NSPI to include detailed five year forecasts of OM&G costs in all future  
rate applications.  
14.14 Demand Side Management  
[706] The Board commends NSPI in its effort in preparing a DSM Plan. All intervenors and  
consultants generally agree that DSM is important and that it ought to be pursued. However, the  
Board considers that approval of the Plan, as submitted by NSPI, is premature at this time. The Plan  
needs additional design work and resources. NSPI customers expect that any DSM program should  
be carefully designed to ensure its maximum impact, and effectively implemented.  
[707] The Board approves $550,000 in additional funds (and not the $5 million requested by NSPI)  
to retain an outside consultant and to complete the Plan=s design and development. NSPI is directed  
to prepare the terms of reference for the consultant and submit them to the Board for approval no  
later than April 15, 2006. The process of retaining and selecting the consultant will be monitored by  
the Board. The Board orders that NSPI complete the DSM Plan and file it with the Board no later  
than June 30, 2006, utilizing the assistance of the Board approved consultant.  
[708] The Board orders that a separate hearing on DSM be held in the second half of 2006.  
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14.15 Depreciation  
[709] The Board approves the resumption of the second year phase-in of the four year increase of  
depreciation rates in the 2006 test year.  
14.16 Annually Adjusted Rates/Below-the-Line Rates  
[710] The Board has not received any evidence in opposition to NSPI=s proposed GRLF rates and  
they have been calculated as in previous years. Accordingly, the 2006 GRLF rates proposed by  
NSPI are approved by the Board effective January 1, 2006.  
[711] There were no intervenor submissions on either the proposed increase in the 1P-RTP adders  
or the proposed amendment to the tariff. The Board approves the adders and the tariff addition  
proposed by NSPI.  
[712] The Board has decided that ELIIR will be substantially redesigned for 2007. The redesign  
will affect the 2P-RTP rate used in conjunction with ELIIR.  
[713] In light of the unanimous support for the language in the 2P-RTP rate at the time it was  
approved, and the likelihood of substantial change effective January 1, 2007, the Board has decided  
not to approve any changes in the tariff wording at this time. The Board approves the 2P-RTP rate  
in its current form effective January 1, 2006.  
[714] The Board concludes that the FP-DSM/DR rate proposed by SEB is not cost based and  
would create an undue burden on ATL customers. Accordingly, the Board is not prepared to  
approve the FP-DSM/DR rate.  
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[715] It is clear to the Board that ELIIR is not working as it was originally intended to by both  
NSPI and SEB. Therefore, the Board will hold a separate hearing in 2006 to consider a replacement  
for ELIIR, which will become effective January 1, 2007. The Board directs NSPI to file an  
application for a new rate to replace ELIIR, after consultation with its customers, no later than June  
30, 2006.  
[716] For the current year, the Board has been presented with two approaches for setting the energy  
charge in ELIIR. NSPI supports the use of the formula in the existing tariff. The Board understands  
that Dr. Stutz recommends beginning with the LIR - that is the Large Industrial Rate at an 85% load  
factor, less the transformer ownership credit and the value of the interruptible supply credit of $3.43  
per month per kVa. Dr. Stutz then subtracts the value of economic interruptibility, which he  
calculated at $8.43 per MWh. Each of these approaches has strengths and limitations. Dr. Stutz=s  
approach is conceptually correct, but does not provide a fully developed alternative for ELIIR. To  
give weight to each approach, the Board directs NSPI to set the ELIIR energy charge by averaging  
the results produced by the two approaches.  
[717] In setting the ELIIR energy charge, the Board directs NSPI to use the fuel budget and all  
other items having an impact on ELIIR, as approved in this decision. The Board also directs NSPI  
to iterate its rate calculations, to ensure consistency between the LIR charges used to set ELIIR and  
those to be paid by customers on the LIR rate.  
[718] The Board has directed NSPI to develop and file a replacement for ELIIR. Both NSPI and  
SEB have agreed that Dr. Stutz=s approach to the development of such a replacementCbeginning  
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with a firm rate and then specifying credits for interruptibilityChas merit. While the Board concurs,  
it would be prepared to consider other viable options which may be developed.  
[719] NSPI proposed to add Special Condition 5 to the ELIIR tariff, the purpose of which is to  
require customers to file an hourly demand forecast on a day-ahead basis. Because the current  
version of ELIIR is about to be replaced, the Board will not approve any changes in the present tariff  
language. Upon filing, the Board will approve, effective January 1, 2006, the interim ELIIR rate  
calculated in accordance with this decision.  
14.17 Load Forecast  
[720] The Board is not persuaded that NSPI's manual adjustment to its load forecast should be  
approved. The Board concludes that denying the DSM-related load forecast reduction should  
increase variable costs, while corresponding revenues from electricity sales should increase. The  
impact of this finding is estimated to result in a net reduction of $1.6 million in the revenue  
requirement.  
[721] The Board directs that NSPI file its report on the progress of improvements to its load  
forecasting methodology by December 29, 2006. This extension of the filing deadline should allow  
NSPI to incorporate its response to DSM-related load reduction issues.  
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14.18 Unmetered Rates  
[722] The Board directs that a cost of service study be conducted as proposed by NSPI with respect  
to the Unmetered Class. The study shall include a review of the appropriateness of the current  
weighting factor and a review of the rate base, including assets, assigned to the Unmetered Class.  
The study should indicate a breakdown of costs and rate base by municipality. The cost of service  
study results shall be filed with the Board by July 31, 2006.  
[723] The Board directs that the current weighting factor of 5.0 should remain in effect for the  
2006 test year.  
14.19 Miscellaneous Charges  
[724] The Board approves the proposed increases to miscellaneous charges sought by NSPI,  
limiting the proposed increase to the average rate increase for ATL customers. In the event such  
increases result in a charge which exceeds the cost of delivering the service, the charge must be  
capped at the actual cost.  
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14.20 Low Income Consumers  
[725] The AEC submits that the Board has a statutory obligation to protect the public interest by  
ensuring that the services provided by NSPI are affordable for its customers, including low income  
customers. Dalhousie Legal Aid appealed the Board=s 2005 rate decision respecting such issues.  
The appeal is set to be heard by the Nova Scotia Court of Appeal. The Board considers it prudent to  
await the disposition of the appeal before it undertakes any further review of the issues raised by the  
AEC.  
14.21 Pole Attachment Fees  
[726] The setting of the pole attachment fee, as well as the scope of costs recovered under that rate  
and under Amake-ready@charges, were canvassed by the Board in its decision on such issues dated  
January 24, 2002. The Board is satisfied that NSPI=s allocation of costs is in accord with that  
decision and that the Company=s proposed rate increase does not result in a duplication of the  
revenue earned from pole attachment fees and Amake-ready@charges.  
14.22 Renewable and Environmentally Sustainable Energy  
[727] Some of the intervenors asked the Board to consider environmental issues in assessing  
NSPI=s application for a rate increase. While much work remains to be done, the Board is satisfied  
that NSPI is addressing these issues. The Board will continue to monitor the Company=s progress.  
It should be noted that DSM and air emission controls will be the subject of separate hearings held  
by the Board in 2006.  
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14.23 Incentive Compensation Plan Review  
[728] In its March 31, 2005 rate decision, the Board determined that NSPI=s incentive  
compensation plan should be reviewed to determine whether it delivers an equal benefit to both  
shareholders and ratepayers. NSPI=s Incentive Compensation Report was filed with the Board on  
September 30, 2005.  
[729] The Board has engaged Liberty to review NSPI=s Incentive Compensation Report. Any  
issues arising from this review can be addressed in a future rate hearing.  
14.24 Non-Profit Intervenor Costs  
[730] The Affordable Energy Coalition asks the Board for costs in this matter. NSPI has not  
addressed the AEC=s request for costs in its submissions. The Board directs NSPI to file its  
response to this request no later than April 20, 2006. AEC will have an opportunity to file additional  
written submissions on this issue no later than May 1, 2006. Following its review of the  
submissions, the Board will issue a ruling on this request.  
14.25 General Demand Rate Class  
[731] As set out in its 2002 and 2005 rate decisions, the Board considers it desirable to maintain,  
where reasonable, an R/C ratio between 95% and 105% for all classes. The Board continues to  
believe that it is fair and reasonable, in terms of the impact on other ATL customers, for the General  
Demand class to be gradually moved to an R/C ratio of 95% to 105%.  
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14.26 Disallowances and Adjustments/Rate Increase  
[732] The Board has made disallowances and adjustments totalling $67,914,000, which will result  
in a reduction of a corresponding amount for NSPI=s test year revenue requirement. This, in turn, is  
expected to result in an average rate increase of approximately 8.6% for above-the-line customers,  
with an estimated rate increase of approximately 8.9% for domestic customers. The increase in rates  
for above-the-line customers is effective March 10, 2006. All below-the-line rates will be effective  
January 1, 2006.  
An Order will issue accordingly.  
DATED at Halifax, Nova Scotia, this 10th day of March, 2006.  
John A. Morash, Panel Chair  
Roland A. Deveau, Member  
Kulvinder S. Dhillon, Member  
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APPENDIX - A  
List of Witnesses  
On behalf of  
Witness  
NSPI  
Chris Huskilson  
Ralph Tedesco  
Robert Boutilier  
Alan Richardson  
Daniel Muldoon  
Mark Sidebottom  
Ralph Janega  
Emily Medine  
James Taylor  
Daniel Walton  
Kathleen C. McShane  
Zeda Redden  
Greg Blunden  
Nancy Tower  
BOARD COUNSEL  
AVON et al.  
John B. Adger, Jr.  
John Antonuk  
Donald T. Spangenberg  
Lawrence N. Koppelman  
Dr. John Stutz  
Dr. Manfred Raschke  
Mark Drazen  
STORA ENSO & BOWATER MERSEY Richard Marston  
Colin V. Gubbins  
Sharon Hennings  
James Selecky  
Dr. Alan Rosenberg  
CONSUMER ADVOCATE  
Nancy Brockway  
EVENING SESSIONS  
(November 23, 2005 and  
November 24, 2005)  
Mark Parent, MLA, Kings North, Kings County  
Ronald Coleman, on behalf of GPI Atlantic  
David Boudreau, General Manager - RuSh Communications  
Chris Brown - Nova Scotia Federation of Agriculture  
Michael Moeller, Antigonish - on his own behalf  
Mel Boutilier, Exec. Dir. Parker Street Food and Furniture Bank  
Joan Jessome, President, NS Gov=t & General Employees Union  
Ceilidh Auger-Day - Ecology Action Centre  
Peter Nestman - NS Association of Health Organizations  
Warden Richard Cotton, President, Union of NS Municipalities  
Joan Massey, MLA, Dartmouth East NDP Caucus Eastern Shore  
Sid Prest, Candidate, Eastern Shore, NDP Caucus  
Brian Butler, Resident of Fall River  
Document : 112539  
335  
Paul Pettipas, CEO Home Builders Association  
Dave Wright, on his own behalf  
Billy Petit, on his own behalf  
Jim DeWolfe, MLA, Pictou East  
Brooke Taylor, MLA , Colchester-Musquodoboit Valley  
Hon. Murray Scott, MLA, Cumberland South  
Document : 112539  
APPENDIX - B  
List of Formal Intervenors  
Affordable Energy Coalition  
Megan Leslie and Claire McNeil  
Avon et al:  
Avon Valley Greenhouses Ltd.  
Canadian Salt Company Limited  
Cerescorp Company  
Robert Grant, Q.C. and Nancy Rubin  
CKF Inc.  
Copol International Ltd.  
Council of Nova Scotia University Presidents  
Crown Fibre Tube Inc.  
Halifax Grain Elevator Limited  
The Halifax Herald Limited  
High Liner Foods Inc.  
Imperial Oil Limited  
Intertape Polymer Inc.  
J.D. Irving Ltd., Saw Mills Division  
Maritime Paper Products Ltd.  
Michelin North America (Canada) Inc.  
Minas Basin Pulp & Power Company Ltd.  
Oxford Frozen Foods Limited  
Statia Terminals Canada Incorporated  
Trentonworks Limited  
Barrington Wind Energy Limited  
Canadian Manufacturers & Exporters  
Consumer Advocate  
Erik Twohig  
Sirje Weldon and Robert Patzelt  
John Merrick, Q.C. and William L. Mahody  
Anne Warburton  
Ecology Action Centre  
Electricity Consumers Alliance of Nova Scotia  
GasWorks Energy Corp.  
John Woods, P.Eng.  
Dwight Jeans and John Reynolds, P.Eng.  
Ronald Colman, PhD. and Judith Lipp  
GPI Atlantic  
Halifax Regional Municipality  
Mary Ellen Donovan, Cathie O=Toole and Julian  
Boyle  
Heritage Gas Limited  
Dr. Larry Hughes, PhD  
Liberal Caucus Office (Nova Scotia)  
Town of Lunenburg  
Marilyn P. Wappel and Chris Smith  
Danny Graham, MLA and David Macrury  
Norman A. Mossman  
Document : 112539  
Municipal Electric Utilities of NS Co-op  
NAAL  
Donald Regan and Albert Dominie  
Anthony Marsh, C.A.  
New Democratic Party Caucus Office  
Howard Epstein, MLA, Paul Black and  
Lorraine Glendenning  
Province of Nova Scotia - Dept. of Energy  
RuSh Communications Ltd.  
Stephen T. McGrath, Allan L. Crandlemire and  
Scott McCoombs  
David Boudreau  
Stora Enso Port Hawkesbury Limited and  
Bowater Mersey Paper Company Limited  
George T.H. Cooper, Q.C. and David S. MacDougall  
Document : 112539  
APPENDIX - C  
SUMMARY  
2006 Cash Working Capital Requirement  
(Dollars in Millions)  
Category  
Lag  
Days  
(a)  
Net  
Lag Days  
Rev Lag - (a)  
% of  
Year  
(b)/365  
Annual  
Cost  
(d)  
CWC  
(c) x (d)  
(e)  
NSPI  
Revenue lag  
42  
Labour  
15  
45  
30  
(91)  
30  
27  
(3)  
12  
133  
12  
7.40%  
(0.82)  
3.29  
36.44  
3.29%  
$119.3  
90.5  
479.0  
32.6  
$8.8  
(0.7)  
15.7  
11.9  
2.8  
Non-labour operating  
Fuel & purchased power  
Grants in lieu of taxes  
Income taxes  
84.4  
Total  
38.5  
(7.0)  
$31.5  
Less customer deposits  
CWC requirement  
DRAZEN  
Revenue lag  
19.2  
Labour  
Non-labour operating  
Fuel & purchased power  
Grants in lieu of taxes  
Income taxes  
Interest on long-term debt  
Preferred dividends  
HST  
21  
50  
29.5  
(91)  
53  
(1.8)  
(30.8)  
(10.3)  
110.2  
(33.8)  
(72.0)  
(26.4)  
(45.0)  
(0.3%)  
(8.4)  
(2.8)  
30.2  
(9.3)  
(19.7)  
(7.2)  
(12.3)  
$119.3  
90.5  
479.0  
32.6  
$(0.6)  
(7.6)  
(13.5)  
9.8  
(7.8)  
(17.8)  
(1.0)  
84.4  
90.0  
14.1  
75.7  
91.2  
45.6  
(9.3)  
Total  
Less customer deposits  
CWC requirement  
(47.8)  
(7.0)  
($54.8)  
SELECKY  
Revenue lag  
22.8  
Labour  
Non-labour operating  
Fuel & purchased power  
Grants in lieu of taxes  
Income taxes  
Interest (long & short-term debt)  
Preferred dividends  
Total  
15  
45  
30  
(91)  
30  
82.7  
45.6  
7.8  
(22.2)  
(7.2)  
68.2  
(7.2)  
2.1  
(6.1)  
(1.9)  
18.7  
(1.9)  
(16.4)  
(6.2)  
$119.3  
90.5  
479.0  
32.6  
84.4  
101.3  
14.1  
2.5  
(5.5)  
(9.4)  
6.1**  
(1.7)  
(16.6)  
(0.9)  
(59.9)  
(22.8)  
Less customer deposits  
CWC requirement  
(25.6)  
(7.0)  
(32.7)  
* Error in Selecky=s calculation  
Note:  
The figures calculated above are then averaged with the calculation for the 2005 F, resulting in an  
average CWC requirement quoted by the parties.  
Document : 112539  
-339-  
Conservation & Energy Efficiency Plan 2006 - Detailed Summary Table  
Residential  
Commercial  
Industrial  
Totals  
Plan Elements  
2005  
Expenditure $  
2007 GWh  
Savings  
2006  
Expenditure $  
2007 GWh  
Savings  
2006  
Expenditure $  
2007 GWh  
Savings  
2006  
Expenditure $  
2007 GWh  
Savings  
1
2
3
4
Lighting  
$980,000  
$295,200  
$311,250  
$558,750  
32.65  
4.72  
3.60  
4.80  
1
2
3
4
$290,000  
$73,000  
3.41  
1.08  
8
9
$0  
$0  
0.00  
$1,270,000  
$368,200  
$590,000  
$745,000  
36.06  
Price Awareness  
Workshops  
0.00  
5.80  
6.80  
6.13  
$201,000  
$149,000  
2.30 10  
1.13 11  
$77,750  
$37,250  
0.90 13  
0.20 14  
Youth Education  
5
6
Leveraging Partnerships  
EnerGuide For Houses  
$560,000  
$497,500  
9.83  
2.67  
5
6
$163,000  
$0  
2.59 12  
0.00  
$0  
$0  
0.00  
0.00  
$723,000  
$497,500  
12.42  
2.67  
7
8
EnerGuide For New Houses  
Pricing Design  
$150,000  
$75,000  
1.70  
0.00  
7
$0  
0.00  
0.00  
$0  
0.00  
0.00  
$150,000  
$300,000  
1.70  
0.00  
$90,000  
$135,000  
9
Other Future Programs  
$297,300  
0.00  
$100,000  
0.00  
$35,000  
0.00  
1.10  
$432,300  
0.00  
Plan Totals  
$3,725,000  
59.97  
$1,066,000  
10.51  
$285,000  
$5,076,000  
71.58  
Notes:  
1a  
1b  
1c  
2
25% of homes use 4 CFL's, (.25 x 393,078 home x 4 CFLs/homes x 45 W/CFL x 5 hr/d x 365 day/yr x 1 GW/1,000,000,000W = 32.28 GWh)  
0.5% of homes use 2 LED night lights (.005 x 393,078 x 2 lights x 4.7 W/light x 9 hr/day x 365 day/yr x 1 GW/1,000,000,000 = 0.06 GWh)  
Holiday LED promotion results in 12,500 sets of lights being replaced (12,500 sets x 123 W/set x 200 hr/season x 1 GW/1,000,000,000W = 0.31 GWh)  
3% of homes save 400 kWh/y (.03 x 393,078 x 400 kWh x 1 GW/1,000,000kW = 4.72 Gwh)  
2000 homes save 1800 kWh/y (2000 homes x 1800 kWh/home x 1 GW/1,000,000kW = 3.6 Gwh)  
6000 homes save 800 kWh/y (6000 x 800 kWh x 1 GW/1,000,000kW = 4.8 Gwh)  
3
4
5
25% of homes save 100 kWh/y (.25 x 393,078 homes x 100 kWh/home x 1 GW/1,000,000kW = 9.83 GWh)  
425 homes save 4017 kWh/y in heating (425 x 4017 kWh/y x 1 GW/1,000,000kW = 1.71 GWh)  
2400 homes save additional 400 kWh/y (2400 x 400 kWh/y x GW/1,000,000kW = 0.96 GWh)  
250 new homes save 6800 kWh/y in heating (250 x 6800 kWh/y x 1 GW/1,000,000kW = 1.70 GWh)  
3000 Businesses install 8 CFL's (3000 x 8 CFLs/business x 45 W/CFL x 10 hr/day x 5 day/wk x 52 wk/yr x 1 GW/1,000,000,000W = 2.81 GWh)  
1000 Businesses install 2 LED Exit Signs (1000 x 2 x 300 kWh x 1 GW/1,000,000kW = 0.60 GWh)  
900 Businesses save 1200 kWh/y (900 x 1200 kWh x 1 GW/1,000,000kW = 1.08 GWh)  
6a  
6b  
7
8a  
8b  
9
10  
11  
12  
13  
14  
1150 Buisnesses save 2000 kWh/y (1150 x 2000kWh x 1 GW/1,000,000kW =2.3 GWh)  
600 Buisnesses save 1875 kWh/y (600 x 1875 kWh x 1 GW/1,000,000kW = 1.13 GWh)  
15% of Buisnesses save 575 kWh/y (.15 x 30,000 Buisnesses x 575 kWh/Business x 1 GW/1,000,000kW = 2.59 GWh)  
75 Industrials save 12,000 kWh/y (75x 12,000 kWh/y x 1 GW/1,000,000kW = 0.90 GWh)  
60 Industrials save 3,350 kWh/y (60 x 3350 kWh/y x 1 GW/1,000,000kW = 0.20 GWh)  
Document : 112539  
2006 NSUARB 23 (CanLII)  
-340-  
Document : 112539  
2006 NSUARB 23 (CanLII)  


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