DECISION NSUARB-NSPI-P-875 2002 NSUARB 59

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., Chair Margaret A. M. Shears, Vice-Chair John L. Harris, Q.C., Member

COUNSEL: NOVA SCOTIA POWER INCORPORATED Peter W. Gurnham, Q.C. Daniel M. Campbell, Q. C.

ANNAPOLIS GROUP et al. Robert G. Grant, Q.C. Nancy G. Rubin

DALHOUSIE LEGAL AID SERVICE Claire McNeil

ELECTRICITY CONSUMERS ALLIANCE OF NOVA SCOTIA John Woods, P. Eng.

HALIFAX REGIONAL MUNICIPALITY Mary Ellen Donovan

MUNICIPAL ELECTRIC UTILITIES OF NOVA SCOTIA CO-OPERATIVE Donald Regan Albert Dominie

PROVINCE OF NOVA SCOTIA Jeannine Lagassé

Document : 78377 STORA ENSO PORT HAWKESBURY LIMITED and BOWATER MERSEY PAPER COMPANY LIMITED George T. H. Cooper, Q.C. David S. MacDougall

TRENTONWORKS LIMITED et al. A. William Moreira, Q. C. Ben R. Durnford

HEARING DATES April 22-26 and 29-30, May 1-3, 13-17, 21-24 and June 3-4, 2002

FINAL SUBMISSIONS June 24, 2002

LIST OF WITNESSES APPENDIX - A

LIST OF INTERVENORS APPENDIX - B

BOARD COUNSEL: S. Bruce Outhouse, Q.C.

BOARD COUNSEL’S CONSULTANTS: Dr. John Stutz, Tellus Institute

James A. Rothschild Rothschild Financial Consulting

DECISION DATE: October 23, 2002

DECISION: Requested Revenue Requirement increase of $67.1 million reduced to approximately $24.7 million; Proposed average rate increase across all classes of 8.9% reduced to approximately 3.3%.

Document : 78377 TABLE OF CONTENTS

1.0 INTRODUCTION ...... 1

2.0 BACKGROUND ...... 6

3.0 TEST YEAR REVENUE AND LOAD FORECAST...... 16 3.1 Load Forecast and Revenues...... 16 3.1.1 Submission - NSPI ...... 16 3.1.2 Submissions - Intervenors...... 18 3.1.3 Findings...... 18

4.0 TEST YEAR EXPENSES...... 20 4.1 Fuel Costs...... 20 4.1.1 Submission - NSPI ...... 20 4.1.2 Submissions - Intervenors...... 24 4.1.3 Findings...... 27 4.2 CBDC Buyout...... 30 4.2.1 Submission - NSPI ...... 30 4.2.2 Submissions - Intervenors...... 34 4.2.3 Findings...... 37 4.3 January Adjustment ...... 38 4.3.1 Submission - NSPI ...... 38 4.3.2 Submissions - Intervenors...... 41 4.3.3 Findings...... 43 4.4 Hydro...... 44 4.4.1 Submission - NSPI ...... 44 4.4.2 Submissions - Intervenors...... 44 4.4.3 Findings...... 46 4.5 Compensation...... 47 4.5.1 Submission - NSPI ...... 47 4.5.2 Submissions - Intervenors...... 48 4.5.3 Findings...... 52 4.5.3.1 Executive Compensation...... 52 4.5.3.2 Incentive Compensation...... 56 4.6 Operating, Maintenance and General Expenses (OM&G) ...... 58 4.6.1 Submission - NSPI ...... 58 4.6.2 Submissions - Intervenors...... 60 4.6.3 Findings...... 63 4.7 Depreciation Expense ...... 67 4.7.1 Findings...... 67

Document : 78377 5.0 CAPITAL STRUCTURE AND RATE OF RETURN...... 68 5.1 Capital Structure ...... 68 5.1.1 Submission - NSPI ...... 68 5.1.2 Submissions - Intervenors...... 70 5.1.3 Findings - Capital Structure...... 72 5.2 Rate of Return on Equity ...... 73 5.2.1 Submission - NSPI ...... 73 5.2.2 Submissions - Intervenors...... 75 5.2.3 Findings - Rate of Return on Equity ...... 78 5.3 Return on Rate Base...... 78 5.3.1 Findings...... 78

6.0 AFFILIATE ACTIVITY...... 81 6.1 Code of Conduct - PricewaterhouseCoopers Report...... 81 6.1.1 Submissions...... 81 6.1.2 Findings...... 85 6.2 Emera Energy - Agency Agreement...... 87 6.2.1 Submission - NSPI ...... 87 6.2.2 Submissions - Intervenors...... 90 6.2.3 Findings...... 95 6.3 Shared Services Allocation ...... 101 6.3.1 Submission - NSPI ...... 101 6.3.2 Submissions - Intervenors...... 102 6.3.3 Findings...... 104 6.4 Coal Transportation Costs ...... 106 6.4.1 Submission - NSPI ...... 106 6.4.2 Submissions - Intervenors...... 108 6.4.3 Findings...... 109 6.5 Independence and Insulation...... 111

7.0 COST OF SERVICE, RATE DESIGN AND OTHER RATE-MAKING ISSUES.116 7.1 Overview - Rate-making Issues ...... 116 7.2 Cost of Service Study...... 117 7.2.1 Submissions - NSPI ...... 117 7.2.2 Submissions - Intervenors...... 118 7.2.3 Findings...... 119 7.3 Revenue/Cost Ratios and Rate Shock...... 119 7.3.1 Submissions - NSPI ...... 119 7.3.2 Submissions - Intervenors...... 120 7.3.3 Findings...... 123 7.4 Annually Adjusted Rates...... 124 7.4.1 Submission - NSPI ...... 124 7.4.2 Submissions - Intervenors...... 124 7.4.3 Findings...... 125

Document : 78377 7.5 Rate Design ...... 126 7.5.1 Submissions - NSPI ...... 126 7.5.2 Submissions - Intervenors...... 126 7.5.3 Findings...... 127 7.6 Future Rate Design Proceeding...... 130 7.6.1 Board Directives ...... 130 7.7 Municipal/Large Industrial Rate Relationship...... 131 7.8 Green Rider Rate...... 132 7.8.1 Submission - NSPI ...... 132 7.8.2 Submissions - Intervenors...... 132 7.8.3 Findings...... 133

8.0 RULES AND REGULATIONS...... 134 8.1 Submission - NSPI...... 134 8.2 Submissions - Intervenors...... 135 8.3 Findings...... 135

9.0 OTHER ISSUES ...... 136 9.1 Regulatory Process - Timing...... 136 9.2 Disclosure ...... 138 9.3 Process Improvements ...... 140 9.4 Dalhousie Legal Aid Service ...... 142

10.0 SUMMARY OF DISALLOWANCES AND ADJUSTMENTS...... 145

11.0 SUMMARY OF BOARD FINDINGS...... 147 11.1 Revenue Requirement/Rate Increase...... 147 11.2 Capital Structure ...... 147 11.3 Rate of Return on Equity...... 148 11.4 January Adjustment ...... 148 11.5 Coal Costs...... 149 11.6 CBDC Buyout...... 149 11.7 Hydro Generation...... 150 11.8 Executive Compensation ...... 150 11.9 Incentive Compensation...... 151 11.10 Operating, Maintenance and General Expenses ...... 152 11.11 Sponsorships and Donations ...... 153 11.12 Affiliate Activity...... 153 (A) Code of Conduct ...... 153 (B) Agency Agreement...... 154 (C) Shared Services Allocation...... 157 (D) Coal Transportation Contract ...... 158 (E) Independence and Insulation ...... 159

Document : 78377 11.13 Cost of Service, Rate Design and Other Rate-Making Issues ...... 160 (A) Compliance Filing...... 160 (B) Cost of Service Methodology...... 161 (C) Revenue/Cost Ratios and Rate Shock...... 161 (D) Annually Adjusted Rates ...... 162 (E) Rate Design...... 163 (F) Future Rate Design Proceeding ...... 163 11.14 Municipal/Large Industrial Rate Relationship...... 164 11.15 Green Rider Rate...... 164 11.16 Depreciation Expense ...... 164 11.17 Load Forecasting ...... 165 11.18 Dalhousie Legal Aid Service ...... 165 11.19 Regulatory Process...... 166

APPENDIX - A Lists of Witnesses ...... 168

APPENDIX - B List of Intervenors...... 170

APPENDIX - C Interim Code of Conduct ...... 172

APPENDIX - D Board Disclosure Order...... 180

APPENDIX - E Board Letter of Clarification...... 187

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1.0 INTRODUCTION

[1] This decision is further to a public hearing conducted by the Nova Scotia

Utility and Review Board (the Board) over 21 days between April 22, 2002 and June 4, 2002 in the matter of an application by Nova Scotia Power Incorporated (NSPI, the Company, the Utility) 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 (Emera).

[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, 2001, served approximately 445,000 customers including six municipal electric utilities. Its revenues for the year

2001 were $838.6 million and its total assets as at December 31, 2001 were $2.9 billion.

[4] In this application NSPI is requesting an increase in rates to meet its proposed revenue requirement. Its proposed rate increases will result in an average increase of 8.9% across all classes. Certain customers will receive rate increases considerably in excess of this amount. In its application as originally filed, NSPI also requests approval of a return on rate base of 10.25%, a return on common equity of 11% and an increase in the common equity component of its capital structure from 35% to a range of 40% - 45%. NSPI also requests final approval of the Code of

Conduct which governs the relationship between NSPI and its affiliates. It was approved by the

Board on an interim basis on March 16, 2001 and has been in effect since September 16, 2001.

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[5] The hearing was duly advertised in accordance with Sections 64 and 86 of the

Public Utilities Act (“the Act”) R.S.N.S., 1989, c.380, as amended, 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] There were 64 formal intervenors who entered appearances or notices of intervention opposing NSPI’s application. A number of these parties, (identified in Appendix B, attached) were represented at the hearing by Counsel. The Province of Nova Scotia (“the Province”);

Annapolis Group et al. (“Annapolis”) whose Counsel represented approximately 32 intervenors;

Stora Enso Port Hawkesbury Limited and Bowater Mersey Paper Company Limited (“SEB”);

TrentonWorks Limited et al. (“TrentonWorks”), whose Counsel also represented several industrial customers; Halifax Regional Municipality (“HRM”); Dalhousie Legal Aid Service (“DLAS”); the

Electricity Consumers Alliance of Nova Scotia (“ECANS”) and the Municipal Electric Utilities of

Nova Scotia Cooperative (“MEUNSC”) all participated in the hearing. The Board also received 107 letters and e-mails opposing NSPI’s application.

[7] The application for a rate increase was filed by NSPI on December 18, 2001.

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By Order dated December 20, 2001, the Board set down a public hearing on the application to

commence on March 4, 2002 and established a timetable for filings and information requests and

responses (“IRs”) that covered the period from January 7, 2002 to February 28, 2002. Following

public notice of the hearing schedule, a number of intervenors including the Province, SEB,

Annapolis, ECANS and MUENSC filed submissions with the Board requesting an adjournment of

the proceeding. The intervenors cited the magnitude of the proposed increases; the timing of the

application and notice which ran over the Christmas holidays; the time required to engage expert

witnesses; and the time necessary for intervenors to adequately prepare their case, as grounds for the

requested adjournment. By Order dated January 22, 2002 the Board agreed, over NSPI’s objections,

to an adjournment and set out a revised timetable which provided additional time for IRs to be issued

and responses filed. The revised date for the commencement of the hearing was April 22, 2002.

[8] On March 8, 2002 an application was filed with the Board by SEB and

Annapolis “...to compel NSPI to provide better and fuller responses” to certain IRs. A hearing on the application was held on March 11, 2002 and, in an Order dated March 12, 2002, (Appendix D, attached) the Board rejected NSPI’s argument that the information sought should not be disclosed, even on a confidential basis. The Board ordered that certain designated confidential information

(DCI) be made available for inspection at NSPI’s offices to those parties who participated in the

disclosure hearing and who signed confidentiality undertakings in a form approved by the Board.

The DCI related to:

(a) fuel supply contracts; (b) fuel transportation contracts; (c) tender documentation related to (a) and (b) above; (d) correspondence and documents relating to negotiation of termination of the long-term CBDC coal supply contract, (sometimes referred to as the

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contract “buyout”) including original coal contract and amendments, termination agreement and arbitration agreement; (e) generating unit-specific production and cost information, on a monthly basis, including but not limited to heat rates, monthly forecast MWh of supply, cost of each fuel source, and quantities and qualities of fuel to be used by fuel source; (f) an explanation of the assumptions and calculations underlying the information provided above. (Board Order on Disclosure Application, March 12, 2002)

[9] As a result of the Board’s Order, (and subsequent letter dated March 22, 2002 which resolved a dispute between NSPI and Annapolis as to the scope of the March 12, 2002 Order, attached as Appendix E), those intervenors who signed confidentiality undertakings reviewed the

DCI at NSPI’s offices. Certain intervenors presented evidence and made submissions based on the information reviewed and this evidence was filed with the Board on a confidential basis. To the extent that any submission includes references to DCI, portions of the evidence available to the

Board do not form part of the public record of the hearing. Similarly, when confidential information was the subject of testimony of witnesses at the hearing, the Board conducted those parts of the hearing on an in camera basis. Accordingly, certain testimony, undertakings, exhibits and transcripts relating to confidential information were (and continue to be) available only to the Board and those parties who signed confidentiality undertakings. Redacted versions of this evidence are a matter of public record.

[10] 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

Document : 78377 5 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.

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2.0 BACKGROUND

[11] NSPI is a vertically integrated, investor-owned, regulated public utility with a virtual monopoly on electricity service throughout the Province. In 2001, it supplied 97% of the generation, 99% of the transmission and 95% of the distribution in the Province. 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 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 supplying a particular service to or for the public, as of a date to be fixed by the Board.

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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) necessary working capital; (b) 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) 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; (e) 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.

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 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.

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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.

[12] NSPI last filed an application for a general rate increase on August 17, 1995.

The Hearing was held in January of 1996 and the Board’s decision was rendered on March 4, 1996.

[13] The Board summarized its 1996 decision, in part, as follows:

SUMMARY OF DECISION 1. NSPI requested an increase in rates of $21.6 million which would have resulted in an average increase of 3.0% over present revenue. The Company requested a return on shareholder equity of 12.0%. The Board has reduced the requested increase by approximately $11 million. This will result in an average rate increase of 1.85% but vary by customer classes from a reduction of 8.0% to an increase of 5.0%. The reduction in rates is the result of reducing the cost recovery ratio for certain classes to 105. The Domestic class will continue to have the lowest revenue/cost ratio of any of the customer classes at approximately 94%. The reduction is attributable to a reduction in the shareholder return of 1.25%, the allocation of some promotional and employee incentive expenses to shareholders and a revised accounting treatment for the carrying costs of the Glace Bay generating station. Approximately $6 million of the reduction has been used to reduce the excess cost recovery for the Small General, General and Small Industrial Rate customer classes. The delay in the rate adjustment to March 1 amounts to a saving of $4.2 million to all customers. The Domestic Rate block structure and base charge have been adjusted to reduce the proposed impact on low-consumption customers.

2. The Board is of the opinion that voluntary time-of-day rates are the most appropriate form of cost reducing rate design at this time and that they are economic, necessary and desirable. To ensure that there is an economic incentive for the Company, the Board accepts electric thermal storage and hot water storage technologies as capital expenditures within the regulated rate base providing that the equipment is handled on a direct-to-customer basis and a lease-to-own basis.

3. The Board is of the opinion that a considerable portion of the funds spent under the DSM program should be consistent with the introduction of Time-of-Use Rates, heat/hot water storage systems and other load shifting or consumption technologies. The Board has, therefore, provided for an additional DSM budget of $500,000 in the

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revenue requirement for individually approved projects relating to these promotion and demonstration activities.

4. The Board determines that a return on equity in the range of 10.5% to 11.00% is just and reasonable. Rates will be determined on the basis of a return on equity of 10.75%, which is 1.25% less than the requested return on shareholder equity. This will result in a projected interest coverage of 1.70. The Board approves a return on rate base of 11.09%.

5. The Board continues to be of the opinion that a range of 8% to 10% for preferred share capital and a range of 33% to 35% for common share capital is appropriate for the capital structure of NSPI and has so approved.

6. The Board approves a one year delay in the schedule for amortizing the deferral of certain Point Aconi costs. The Board does not accept the Company proposal that severance costs that exceed 0.25% of the revenue requirement should be deferred. The modified plan will last approximately six months longer than the original plan and will moderate the required 1996 rate increase.

7. NSPI proposes to amortize the $27 million associated with the 1995 severance separation and early retirement plan over a five year period. The Board approves the deferral but directs that the deferral be over a three year period.

8. In this decision the Board has made adjustments in the revenue requirement such that the proposed cost recovery ratios of the Small General, General and Small Industrial classes have been reduced. In future rate filings, should NSPI propose rates such that the cost recovery ratio exceeds 1.05, the Board will revise the proposed revenue requirement accordingly.

9. By Order dated March 8, 1994, the Board directed NSPI to undertake an investigation of rate designs that are consistent with cost reductions under the Integrated Resource Plan. Rate alignment relates to the concept that future costs should be reflected in the rate design so as to allow customers to make proper investment decisions and that rates should be based on costs to the extent that increased efficiency in the total utility system which will reduce costs to all customers. It is the Board’s opinion that rates should never be set below short-run marginal costs. Long-run marginal costs should be used to temper the wide fluctuations that can exist in the year-to-year levels of short run marginal costs.

10. The Board has determined that it is appropriate to combine the Large Industrial and the Interruptible Customer into a single class and offer interruptible customers a demand credit. Limits of interruptibility will also be established. The Board considers that transmission costs of $2.8 million dollars are properly attributed to the class. Eligibility for the Large Industrial rate will be reduced to 2000 kVA as requested by NSPI. Because there is a disproportionate impact on the low load factor customer, the demand discount for certain customers will be phased in over five years.

11. The Board approves certain amendments to the regulations in regard to underground electric wiring, billing adjustments, settlement agreements, deposits and charges. The Board approves a revised pole attachment charge for cable

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television of $9.60 per pole per year. (NSPI Decision, P-868, pp.96-102)

[14] As noted above, in the six years since the last hearing, NSPI has become a

subsidiary of Emera, and other Emera subsidiaries are numerous and active in energy-related business endeavours. A regulatory regime for natural gas distribution has been established in Nova

Scotia although at the present time natural gas is available only to a limited number of users from laterals connecting to the Maritimes and Northeast Pipeline. The Province has adopted an energy strategy which has the potential to impact NSPI’s monopoly status over time.

[15] While capital expenditures by NSPI in excess of $25,000 require Board approval, the Act was amended in 1992 to provide for a consolidated Annual Capital Expenditure

Plan (ACE Plan). Each year, the Board considers NSPI’s total proposed capital expenditures on planned and routine items under $1,000,000 in one consolidated filing. Items over $1,000,000, or those classified as Unknown and Unforeseen and not included in the ACE plan, are reviewed on an individual basis by the Board.

[16] NSPI’s operating expenses have not been subject to Board review since 1996 as its earnings on common equity did not materially exceed the 11.00% cap approved by the Board.

The setting of a range of permissible earnings on common equity (10.5% - 11.00% in the 1996 decision) is somewhat similar to performance-based regulation which is generally considered to be a more light-handed form of regulation than traditional cost of service regulation. It gives the utility an incentive to effect cost savings in order to earn above the return approved for rate making purposes

(10.75% in 1996) and enables it to avoid frequent rate reviews as long as it maintains its earnings within the permitted range.

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[17] In its current application NSPI has chosen 2002 as its test year. It estimates substantially higher expenses in 2002 over 2001. The increase is principally caused by higher fuel costs (particularly coal) including associated increased foreign exchange costs. Unlike its experience in 2001, NSPI does not foresee the possibility of offsetting coal price increases with profits from natural gas sales. As summarized in the direct evidence of Dr. John Stutz, a principal of the Tellus

Institute and consultant to Board Counsel, the requested increase in rates is due primarily to an increase of $35.5 million in coal costs and a decrease in natural gas sale revenues of $32 million. In addition, NSPI considers that the earnings range on common equity approved by the Board in 1996 is no longer adequate. Other issues cited by NSPI as factors in its decision to apply for a rate increase are environmental concerns, increased business risk and competition, and NSPI’s future income tax liabilities. NSPI has concluded that the existing rates no longer permit it to both cover its operating costs and earn an acceptable return. In its original application, it requested approval of rates which, if effective on January 1, 2002, would result in a revenue increase of $67.1 million.

[18] In using a test year ending December 31, 2002, NSPI necessarily used forecast data for the full test period. In its initial filing, NSPI advised that:

Because of the volatility of certain costs for the test year, NSPI will provide an updated 2002 forecast by January 28, 2002, even if no change to the revenue requirement is warranted. (Exhibit N-1, p.16)

[19] NSPI did, in fact, file an updated financial forecast for 2002 on January 28,

2002. It contained a number of adjustments to revenues and expenses, the net effect of which was that no change in revenue requirement was indicated. Much time was spent at the hearing debating the implications of the various adjustment items included in the January 28, 2002 revision.

[20] The Board has considered what use it should make of the information

Document : 78377 13 contained in the January 28, 2002 letter and in the tables filed in conjunction with the letter. For

many years the Board has permitted applicants seeking rate increases to use a forward-looking test

year using projected data for that purpose. On occasion, applicants may have used a combination of

actual and projected data for test year purposes. In the present instance, where the January 28, 2002

data makes no difference to the Company’s ultimate revenue requirement and only one month of

actual data is included in any event, and for reasons which are set out in Section 4 of this decision,

the Board is of the opinion that it would be appropriate for it to disregard the January 28, 2002 filing

and to use projected data only for the full 2002 test year.

[21] In utility regulation, there are generally accepted principles which govern the

rate-making exercise. The object of rate-making under a cost-of-service-based model is that, to the extent reasonably possible, rates should reflect the cost to the utility of providing electric service to each distinct customer class. In regulating NSPI, the Board is guided by these generally accepted principles as well as by case law.

[22] A widely-accepted publication written by Dr. James Bonbright entitled

Principles of Public Utility Rates, sets out the following guidelines for determining appropriate rates:

CRITERIA OF A SOUND RATE STRUCTURE

1. The related, "practical" attributes of simplicity, understandability, public acceptability, and feasibility of application. 2. Freedom from controversies as to proper interpretation. 3. Effectiveness in yielding total revenue requirements under the fair-return standard. 4. Revenue stability from year to year. 5. Stability of the rates themselves, with a minimum of unexpected changes seriously adverse to existing customers. (Compare "The best tax is an old tax.") 6. Fairness of the specific rates in the apportionment of total costs of service among the different consumers. 7. Avoidance of "undue discrimination" in rate relationships.

Document : 78377 14

8. Efficiency of the rate classes and rate blocks in discouraging wasteful use of service while promoting all justified types and amounts of use: (a) in the control of the total amounts of service supplied by the company; (b) in the control of the relative uses of alternative types of service (on- peak versus off-peak electricity, Pullman travel versus coach travel, single-party telephone service versus service from a multi-party line, etc.). (Exhibit N-92) (James Bonbright, Principles of Public Utility Rates, Columbia University Press, 1961, p. 291)

[23] These principles are well established and form the background against which the current application must be assessed.

Document : 78377 15

3.0 TEST YEAR REVENUE AND LOAD FORECAST

3.1 Load Forecast and Revenues

3.1.1 Submission - NSPI

[24] NSPI’s estimate of revenue from the sale of electricity is based on its forecast

of electric energy and peak demand requirements to be met in the forecast period. Estimates are

developed using econometric and end-use models and large customer energy surveys. In its load

forecast, NSPI summarizes the resulting sales, losses and total energy requirement for the years

1995-2002, including the energy required by the six municipal electric utilities.

[25] NSPI filed a load forecast with its original application as follows:

Table 4.1 LOAD Forecast (GWh) - 1996-2000 Actual and 2001-2002 Forecast Year Residential Commercial Industrial Exports Losses Requirement GWh % GWh % GWh % GWh % GWh GWh %

1995 3470 2686 2862 1 656 9675 1996 3568 2.8 2714 1.0 2774 -3.1 73 NA 696 9825 1.6 1997 3598 0.8 2720 0.2 2863 3.2 319 337.3 803 10303 4.9 1998 3467 -3.6 2688 -1.2 3442 20.2 160 -49.8 749 10506 2.0 1999 3559 2.6 2752 2.4 3848 11.8 197 22.6 723 11079 5.4 2000 3697 3.9 2837 3.1 3931 2.1 181 -8.1 786 11432 3.2

2001 3826 3.5 2881 1.6 3907 -0.6 297 64.1 802 11713 2.5 2002 3904 2.0 2982 3.5 4008 2.6 295 -0.7 819 12008 2.5 (Exhibit N-1, Table 4.1)

[26] Based on these forecasts, NSPI developed its revenue estimate for 2002 as

follows:

Nova Scotia Power Inc.Table 3.6 Detail of Electric Revenue st MillionsYears Ended of Dollars Decembe r 31

Document : 78377 16

(1) (2) (3) Proposed(4) Proposed(5) PresentRates TestRates Year (MayRates 1st ) Actual2000 Forecast2001 Forecast2002 Forecast2002 Forecast2002

RESIDENTIAL $351.6 $361.6 $367.6 $400.4 $387.5 GENERAL Small General 12.4 8.7 8.9 9.7 9.4 GeneralLarge General Demand 192.422.6 200.122.8 206.023.2 216.427.0 212.625.8

Total General 227.4 231.7 238.1 253.0 247.9

INDUSTRIAL Small Industrial 16.6 16.3 16.9 18.5 18.0 LargeMedium Industrial Industrial 81.832.8 72.033.7 71.834.9 83.39.36 79.737.9 &Generation Load Following Replacement 14.5 17.8 17.8 18.5 18.5 MerseyIndustrial Expansion 43.46.1 49.06.5 54.76.7 57.26.7 57.26.7 RealSurplus Time Power Pricing Interruptible 2.1- 5.0- 9.1- 9.4- 9.4-

Total Industrial 197.3 200.4 212.0 233.2 227.5 OTHER

Municipal 10.4 10.7 11.1 12.9 12.2 UnmeteredOther Electric 17.71.7 (1.1)17.2 18.5- 18.5- 18.50

Total Other 29.8 26.9 29.6 31.4 30.8

TOTALELECTRIC IN-PROVINCE REVENUE 806.1 820.5 847.3 918.0 893.6

EXPORT CONTRACT SALES - 1.7 13.5 13.5 13.5 OTHER EXPORT SALES 7.2 11.1 2.9 2.9 2.9

TOTAL ELECTRIC REVENUE $813.3 $833.3 $863.7 $934.3 $910.0 (Exhibit N-1, Table 3.6)

[27] It is of interest that, in recent years, gas sales have also formed part of NSPI’s revenues. However, NSPI states that:

Natural gas prices have declined markedly from their levels in 2000 and 2001. During that period NSPI has been able to sell gas which it acquires under firm contracts while burning lower-cost oil, thus reducing the net cost of its fuel. This effect was sufficient to avoid the necessity of rate increases in 2000 and 2001. This option is not expected to be available in 2002. Ironically, this decline in the price of gas has resulted in an increase in the net cost of fuel to NSPI. (Exhibit N-1, pp.37-38)

[28] It should also be noted that NSPI receives revenue as a result of export sales of electricity.

3.1.2 Submissions - Intervenors

[29] While NSPI’s load forecast methodology was not disputed by the intervenors, there were a number of issues relating to the forecast itself which were contested.

[30] One major issue is that in its January 28, 2002 update NSPI adjusted its load

Document : 78377 17 data based on a warmer than normal January in 2002. Intervenors believe that adjusting test year data by introducing “actual” temperature information erodes the value of using forecasted test year data.

3.1.3 Findings

[31] While not a significant issue at this hearing, the Board is cognizant of the fact that the electricity load forecast forms the foundation upon which the application is based. The

Board notes that a large number of information requests were issued by both Board Staff and some of the intervenors for evidence supporting NSPI’s load forecast. The Board is of the opinion that this supporting data should have been filed as part of the original application. As part of any future rate applications, the Board directs NSPI to file all supporting evidence pertaining to the development of its energy and peak demand forecasts. This evidence should include discussions of all econometric models considered and either rejected or chosen.

[32] The Board has reviewed NSPI’s electricity load forecast and supporting data provided in response to information requests and concludes that the load forecast has been developed in a reasonable manner. The Board’s comments on the proposed January adjustment are noted in

Section 4.3 of this decision.

Document : 78377 18

4.0 TEST YEAR EXPENSES

4.1 Fuel Costs

4.1.1 Submission - NSPI

[33] In its application, NSPI stated that:

Approximately 90% of NSPI’s generated energy is produced from fuel-burning thermal plants. In 2002 fuel costs will account for more than 50% of NSPI’s operating costs, and accordingly changes in the delivered cost of fuel have a significant impact on NSPI’s total costs. NSPI has avoided any general price increases since 1996 through a series of prudent management initiatives. However, with the abrupt changes in our fuel markets in 2001, fuel costs will increase dramatically in 2002, beyond the range which can be contained without price increases. (Ex. N-1, p.37)

[34] NSPI witnesses reiterated at the hearing that fuel costs are the primary driver

of the application. NSPI’s ability to generate electricity is heavily dependent on solid fuel - i.e., coal

and petroleum coke (pet coke). This is illustrated by the following exchange between Counsel for

SEB and Christopher Huskilson, Chief Operating Officer of NSPI:

Q. And so it would be fair to characterize the application for a general increase in rates, the one that we're dealing with right now, as driven -- to be driven primarily or maybe even exclusively by the increase in fuel costs, including foreign exchange? A. Yes, certainly those are the major components. As we've stated before, because of the risk that the utility faces and the environment that both the bond rating agencies and investors in general see, it's very important that the capital structure also be addressed in this hearing and we believe that that's an urgent issue for the company, but certainly fuel and foreign exchange is the primary driver to our costs for this year. (Transcript, April 22/02, p.45-46)

[35] NSPI is heavily dependent on coal for the generation of electricity as,

according to NSPI witnesses, approximately 80% of its generation is coal-fired.

[36] Consequently, purchasing coal is the single largest expense for NSPI,

amounting to approximately $200 million in 2001. NSPI submits that the announced closure of the

Cape Breton coal mines in early 2001 by the Cape Breton Development Corporation (CBDC, Devco)

Document : 78377 19 forced NSPI to purchase coal in the international market at a time when coal prices were high. NSPI tendered for coal supply in the spring and fall of 2001 when market circumstances (which have been described by various witnesses as the “perfect storm” scenario) drove coal prices to very high levels.

According to NSPI, this sudden spike in coal prices was outside its control and, coupled with a low

Canadian dollar relative to the US dollar, resulted in cost increases which were beyond the ability of the company to absorb. NSPI projects that profits from natural gas sales (natural gas being available to NSPI under the Shell contract) will decline steeply in the test year and, as a result, NSPI will not have this revenue to mitigate the increased cost of coal.

[37] In 2001, NSPI was also in the process of altering its coal purchasing function.

NSPI entered into an arrangement with Emera Energy Inc., (Emera Energy) under which Emera

Energy acted as NSPI’s fuel acquisition agent. This arrangement, which is discussed more fully in

Section 6.2 of this decision, did not, according to NSPI, change the company’s basic coal

procurement strategy during this period. NSPI’s coal procurement strategy, as outlined in its

application, consisted of purchasing coal in the spring and fall for the following budget year. When

questioned by Counsel for Annapolis concerning NSPI’s strategy compared to that of other U.S.

utilities, Jeff Watkins, of Hill & Associates, NSPI’s coal expert, stated that:

A. ... I was talking there about domestic U.S. utilities that predominantly do not have access to the seaborne market. I don't think it's a fair comparison to compare NSPI to the domestic U.S. utilities. I was speaking about U.S. practices, not seaborne practices. So I would suggest that NSPI does that by staying short in the market, buying twice a year, therefore never getting too out of sync with the market, very similar to what these U.S. utilities do with their short-term procurement strategy with market price adjustments. So from a standpoint of staying close to the market, they're very comparable. From a standpoint of the markets that they play in, they're not comparable. (Transcript, May 2/02, pp.1558-1559)

[38] NSPI witnesses, particularly Mr. Huskilson and James Taylor, Vice President

Document : 78377 20 of Power and Production for NSPI, gave extensive evidence justifying the reasonableness and prudence of NSPI’s coal procurement practices. Much of this testimony was given during in camera

sessions.

[39] In its non-confidential post-hearing brief, NSPI defended its coal purchasing

strategy, arguing that:

Until the spring of 2001 NSPI was subject to a “requirements” coal supply contract with CBDC. The history of that contract is dealt with elsewhere in this argument, but for the purposes of this discussion it is important to understand that CBDC vigorously asserted its right to import coal to supply NSPI’s needs, and an arbitrator had accepted this position (although NSPI considered this finding to be obiter dicta). NSPI was therefore not in a position to bind itself to long-term supply contracts with others. (NSPI, Post-Hearing Brief, p.8)

NSPI’s coal procurement strategy is designed for the market in which it participates. It has adopted a purchase strategy under which it goes to market twice a year, and purchases coal on contracts for delivery about a year in advance. Actual contracts are for delivery 8 to 18 months after contract date. Mr. Watkins explained that long-term (or even medium-term) fixed price contracts are not readily available in the international seaborne market, and that if such contracts are available at all, there would be a significant price premium or non-market escalator. He indicated that the market indices are immature and not completely reliable because there is no mandatory and reliable reporting of international sales data. He was of the opinion that the program of twice-yearly marketing, with contracts for delivery between 8 and 18 months forward, was sound. By staying close to the market it minimized cost in the long run, and minimized the risk that coal costs would ever be significantly above market price. (NSPI, Post-Hearing Brief, pp.10-11)

[40] NSPI also vigorously disputes the allegations by the intervenors that its coal purchasing strategy was imprudent. NSPI asserts that:

The intervenors’ consultants, Ms. Medine and Ms. Hennings, argue that, beginning in 1997, NSPI should have signed long-term purchase agreements for approximately one third or one quarter of its annual coal requirement, renewing expiring contracts as they mature. They describe this as a “portfolio strategy”. They assert that if this had been done, the impact of the “perfect storm” of 2001 would have been mitigated. Ms. Medine’s recommended strategy assumed contractual options would have permitted the company to acquire coal at prior years costs, thus further reducing the cost in the test year. ... If the intervenors’ purchase strategies were applied consistently, and even assuming that long term fixed price contracts were available without premium (and they are not), they lead to exactly the same cost over time. If the 2001 prices are considered a short-term aberration, these strategies would have NSPI paying them for one quarter of its fuel for four years - the same amount. Ms. Hennings insisted that she would vary her purchase pattern, buying heavily when prices are going up and buying short when prices are falling. This hope of

Document : 78377 21

consistently beating the market is the strategy of a speculator, not a prudent utility. Such a strategy can result in prices being seriously out of line with market prices. Further, at the very time that these consultants now suggest NSPI should have been buying long term, all analysts, including Ms. Medine’s firm, were forecasting prices to be either flat or declining. ... NSPI submits that the purchasing strategies of the intervenors’ consultants are unsound. They lead to higher costs in the long term, and in most cases in the short term. Even if they are accepted as “a “ prudent approach, they cannot be said to be uniquely prudent such that any inconsistent strategy is to be penalized as “imprudent".

It must be remembered that NSPI was operating in a very challenging environment. It was bound by a long term “requirements” contract with CBDC. It was in negotiations with CBDC for the renewal of the price and volume terms of that contract, and with proponents who were considering the takeover of the CBDC operations. Finally, it amended its agreement with CBDC, only to learn that the mines were to close. And as this was happening, economic forces converged in international coal markets causing prices to behave in a way that they had never done before, and which was not foreseen by any of the analysts. This was described by various witnesses, including Dr. Stutz, as the “perfect storm”. The intervenors challenge the NSPI purchasing behavior in this challenging situation based on their strategies which they hone with perfect hindsight - the perfect strategies for the perfect storm.

NSPI submits that the standard of “imprudence” must be a high one in order to justify penalizing a utility. It must consist of a course of conduct which cannot be supported by a body of reasonable opinion. In this case the practice of NSPI is not only supported, it is actively recommended by Mr. Watkins, who has experience and expertise in this market. Dr. Stutz fairly characterized the approach as a prudent one. It would be unfair and unreasonable to penalize the utility because intervenors, with the benefit of perfect hindsight, can concoct a scenario under which costs might have been reduced. (NSPI, Post-Hearing Brief, pp.11-14)

4.1.2 Submissions - Intervenors

[41] Two intervenors, SEB and Annapolis, retained experts to review NSPI’s fuel costs. Sharon Hennings, a consultant with Brubaker and Associates, a U.S. based energy consulting firm, and Emily Medine, Principal/Consultant with Energy Ventures Analysis, Inc., of Pittsburgh,

Pennsylvania, gave evidence for SEB and Annapolis respectively. Both experts stated that NSPI’s coal procurement strategy was imprudent and each suggested that the Board significantly reduce

NSPI’s requested revenue requirement for fuel purchasing.

[42] Ms. Hennings, in her evidence (Exhibit N-30), asserted that NSPI was

Document : 78377 22 imprudent by relying too heavily on the spot market for coal. As a result, NSPI had no protection, by

way of term contracts, when coal prices spiked dramatically. Ms. Hennings also took issue with

NSPI’s estimate of ground transportation costs for coal and for pet coke. She indicated in her direct

evidence, and under cross-examination, that these costs were excessive and not representative of a

valid forecast of reasonable costs, stating that:

The 2002 estimated cost of ground transportation in Nova Scotia is based on 2001 prices charged by CBDC and other suppliers. NSPI represents these historical prices to be fair market value prices and representative of the price that will be charged in the test year for the transportation. The ground transportation costs should be reduced to a reasonable level. The prices are very high in comparison with other transportation costs. The cost to transport coal and petroleum coke from Nova Scotia ports to NSPI’s generating plants is almost double the cost to load and ship the coal from Baltimore. It is almost equivalent to the price of loading and shipping coal from Columbia to Nova Scotia. The price forecast being used for Nova Scotia ground transportation is not a valid forecast of reasonable costs for the routes to the Lingan and Point Aconi plants. (Exhibit N-30, p.6)

[43] Ms. Hennings further suggested that downward adjustments should be made to

NSPI’s revenue requirement to account for forecasted coal purchases from distressed vessels,

increased pet coke usage, and increased hydro generation.

[44] Ms. Medine also asserted that, in her view, NSPI was imprudent in its coal

procurement strategy. She noted in her direct evidence that:

Even though NSPI has reduced its forecast of 2002 solid fuel costs, these prices are considerably higher than the solid fuel costs for earlier years and higher than they should be in future years. Further, NSPI bears the responsibility for causing some of the additional cost by not hedging import coal purchases in 1999 when the Phalen mine closed; by not hedging coal purchases in 2000 when there were indications that the coal market was tightening and the future of CBDC became very tenuous; and by not being more aggressive in 2001 when it was clear that the market was tight and decisions needed to be made more quickly. Simply put, NSPI’s stated costs for 2002 are inappropriate costs to be used for a test year. (Exhibit N-39, pp.13-14)

[45] Annapolis, in its closing submission, argues that:

As this is the first rate case in which NSPI has not secured all of its solid fuel requirements from CBDC, this case is the first opportunity for the Board to inquire into the reasonableness and the prudency of NSPI’s fuel procurement policy and fuel expenditures. The fact that

Document : 78377 23

NSPI has committed, by purchase order, to a certain percentage of import coal for the test year, at a certain price, is not determinative of whether or not the Board should allow the expenses. The Board’s regulatory duty is to scrutinize and disallow improper expenditures if they are not necessary and reasonable. The disallowance of improper expenditures which have been made imposes the burden on investors in the form of lower profits and creates an incentive on the managers of the utility to act appropriately, efficiently and with sophistication. ... This coal procurement “strategy” is nothing more than a convenient process. No forward- looking analysis was done at the time of its implementation; in reality NSPI admitted it “landed on this strategy” (Transcript, Taylor, p. 891). · The “strategy” was developed without formal assistance from non-NSPI employees or industry experts (Response to Grant IR-5; Transcript, Huskilson, p.525). · While Jeff Watkins of Hill & Associates was on retainer to provide forecasting reports, he was not consulted in the development of the strategy (Transcript, Huskilson, p.874). · There are no formal reports from third parties vetting the strategy (Transcript, Huskilson, p.1095) · Despite being aware that it is common practice in the U.S. for fossil-fuel based utilities to consult with the regulator on procurement strategy, NSPI did not seek input from this Board (Transcript, Huskilson, p.1096). (Annapolis, Closing Submission, pp.20-22) [46] In his direct evidence, Dr. Stutz did not suggest that NSPI’s coal purchasing was imprudent but did recommend that NSPI’s fuel costs for the test year be reduced by 10%. Dr.

Stutz’s objection to NSPI’s estimated fuel costs is based on his view that the costs are anomalous and are not representative of those that are likely to be incurred over the period in which the rates are to be in effect and, therefore, should not be used for test year purposes. He differentiated this suggestion from the recommendations of Ms. Medine and Ms. Hennings in response to questions from the Board, indicating that:.

. . . They were really -- if I can just elaborate slightly, they were really suggesting three different things. One thing was a very big adjustment, 40 million dollars I think was a figure that appeared. This would be appropriate if you felt that the company's coal procurement was imprudent. That's an open issue. A second thing that was suggested is that there were various shortcomings in the company's justification of its costs. And you could make adjustments of that sort, smaller amounts, generally in the 2 or 3 or 4 million dollar range. A third thing that was suggested by Ms. Medine was that, in fact, even if you believe the company acted in a generally prudent fashion, that because, as far as she could determine, there was no systematic procedure for putting the bid data and the transport data together in a consistent fashion, you simply couldn't determine whether they had succeeded in doing what they set out to do, which was to minimize their costs. And I haven't heard the response to that, but it did seem like a reasonable point. Now, what I've done is separate from all of those I've simply said, even if you thought the approach was generally prudent, you didn't agree with the company -- you didn't agree with the other intervenors that there were these

Document : 78377 24

other adjustments, and you thought somehow or other they'd gotten it right, even if you accepted all of those points, and therefore rejected everything everyone else said, you still might want to make my adjustment because you feel that the coal costs are unrepresentative of what they'll face in 2003. Now, am I being generous to them as to what they'll face in 2003? I don't think so based on the evidence we've heard. Mr. Watkins was very clear that the coal prices are not dropping back to their historic levels very rapidly, and so something which brings you down from the current peak but doesn't, perhaps, take you all the way back to where we've been historically, seems to me consistent. If they dropped faster then yes, I would be overly generous. (Transcript, June 4/02, pp.3980-3982)

[47] Dr. Stutz also indicated that while he did not personally believe NSPI’s coal procurement strategy was imprudent he agreed with Ms. Medine that their “strategy” was not adequately implemented and, therefore, NSPI was unable to demonstrate that coal was obtained at the lowest possible price.

[48] A number of other intervenors (the Province, ECANS, HRM, MEUNSC and

TrentonWorks) support the proposition that NSPI’s estimate of coal prices for the test year were not sufficiently representative of “normal” circumstances and should be reduced.

4.1.3 Findings

[49] The Board has carefully considered all the evidence on the issue of fuel costs including the evidence given during the in camera portion of the proceedings relating to coal costs and purchasing.

[50] In particular, the Board has considered the helpful evidence of Mr. Watkins,

Ms. Medine, Ms. Hennings and Dr. Stutz on the issue of imprudence and that of Dr. Alan Rosenberg, of Brubaker and Associates, an expert retained by SEB, respecting the concept of “used and useful” for the purpose of reviewing utility expenditures.

[51] After evaluating all the evidence concerning NSPI’s coal procurement

Document : 78377 25 strategy, the Board finds that NSPI’s actions do not go so far as to constitute imprudence.

[52] Although NSPI had contracted on the international market for some part of its

coal requirement in the late 1990’s, the bulk of its coal was supplied by CBDC pursuant to a long- term supply agreement dating back to 1978. NSPI’s coal supply situation changed drastically between 1999 and 2001 with the decline in production at CBDC’s mines followed by the announced closure of all of CBDC’s coal mines in the spring of 2001. Accordingly, NSPI has not had a lengthy history of involvement in the international coal markets. The Board surmises that its learning curve has been a steep one. While not imprudent, the Board considers that NSPI’s coal procurement strategy has been lacking in sophistication. However, the Board is not prepared to find that NSPI’s strategy of buying coal pursuant to short-term contracts on the international markets was fundamentally flawed. The Board agrees with Ms. Medine, however, that stringent procedures should be in place to govern coal procurement (i.e., practices and procedures setting out approved methods for issuing bids for coal supply) as coal acquisition accounts for a huge portion of NSPI’s total expenses. The records show considerable sloppiness on NSPI’s part in terms of its purchasing practices, including the interchangeable and confusing use of Emera and NSPI as the contracting party for coal. The Board will address this matter further in Section 6.2 of the decision.

[53] Notwithstanding that the Board does not consider that the evidence supports a finding of imprudence on the part of NSPI, the Board does believe that NSPI’s practices in this area are sufficiently lax so as to undermine NSPI’s ability to ensure, and demonstrate to the Board, that coal was obtained at the lowest possible price. NSPI’s argument that it had an “evolving” relationship with Emera Energy does not justify the confusing document trail in terms of who was

Document : 78377 26 actually contracting for coal. In the Board’s view, there is too much at stake and, consequently, too significant a potential impact on ratepayers, to accept anything less than the best possible business practice.

[54] The Board agrees with the intervenors that the fuel costs for the 2002 test year are based on higher than normal coal costs. The expert witnesses all appear to agree that coal prices have begun to decline and, while costs may remain relatively high, the abnormally high prices seen during 2001 have dropped. Under these circumstances, the Board finds that the test year coal costs

used by NSPI are not suitable for rate-making purposes. In this case, NSPI applied for a rate increase

at the end of 2001 projecting coal costs which were higher than most experts anticipate to be the case

during 2002-03. NSPI is not entitled to recover past expenses caused by high coal prices. It is an

accepted principle, which the Board endorses, that rate-making should be prospective and not

retroactive. NSPI lost the opportunity to mitigate the high cost of coal for a good part of 2002 when

it waited to file an application until December of 2001. Accordingly, the Board finds that the cost of

fuel for the test year must be reduced in order to ensure that the costs are more representative of the

period during which the rates will be in place (i.e., late 2002 and into 2003).

[55] As noted above, since the Board finds that NSPI’s projected fuel costs for the

test year are unusually high, it believes the fuel costs should be “normalized” by reducing the

amount estimated by NSPI. In determining an appropriate reduction the Board notes that Dr. Stutz’s

recommended 10% reduction in imported coal costs moves the price of coal closer to the historic

mean price as shown in Exhibit N-152, JS-5, while still acknowledging the increase in coal prices

which did occur. The Board finds that to normalize these coal costs on a go-forward basis for the

Document : 78377 27 balance of this year and into 2003, a 10% reduction in the test year costs for imported coal is reasonable and balanced. The Board does note that, according to the information in the January 28,

2002 update, NSPI’s actual imported coal costs were less than those originally estimated. In the

Board’s view, a reasonable reduction in test year costs is the 10% suggested by Dr. Stutz. This will

result in a reduction of approximately $19.7 million in the test year revenue requirement.

4.2 CBDC Buyout

4.2.1 Submission - NSPI

[56] NSPI has obtained coal for many years from CBDC. In April 2001, NSPI

entered into an "amending agreement" with CBDC to amend certain terms of the long-term coal

supply contract which had been in effect between the two parties since 1978. The amending

agreement was effective as of January 1, 2000. Among other things, the amending agreement

provided that the long-term coal purchase contract would terminate in 2005 rather than in 2010.

Pursuant to the amending agreement, NSPI incurred a $12.4 million buy-out fee, plus interest costs of $1 million, in connection with the early termination of the long-term coal contract. NSPI proposes that these costs be amortized over a five-year period beginning in 2002 with the amount to be amortized in 2002 being $2.7 million.

[57] NSPI described the long-term contract between it and CBDC as having the following provisions among others:

... The agreement contained no guarantees of quality or quantity to be delivered, but gave CBDC the right to supply up to the entire requirement of NSPI. CBDC took the position that it had the right to import coal to meet NSPI’s requirements, and an arbitrator had accepted that position. CBDC always vigorously asserted this right, although it did not at any time seek to actually import coal on behalf of NSPI. The coal price was renegotiated every five years, and

Document : 78377 28

was subject to arbitration in accordance with the "four factor formula" in the agreement. These factors included the (high) cost of production in the CBDC mines, and the cost of supply of alternate energy sources. (NSPI, Post-Hearing Brief, p. 14)

[58] Again, much of the information pertaining to the coal supply contract was provided on a confidential basis. However, a useful summary of the issue is available in the non- confidential versions of post-hearing submissions. As noted above, NSPI asserts that it was subject to a “requirements” coal supply contract with CBDC which commenced in 1978. NSPI explained that the relationship was further complicated by CBDC’s claim that it had the right to import coal to supply NSPI if necessary.

[59] NSPI stated that:

The history of, and problems with, the CBDC contract are well known to the Board. CBDC coal was of relatively poor quality. It was high in sulphur, and this became more problematic as the environmental emissions limits, which were not an issue when the contract was originally signed, were approached. The agreement contained no specifications for sulphur content, and CBDC refused to agree to any such stipulations. As a partial response, NSPI built the fluidized-bed combustor unit at Point Aconi, which could burn a high-sulphur fuel with minimal emissions. Unfortunately, between the time of design and commissioning of the Point Aconi generator, the quality of coal from the Prince Mine deteriorated (in that its level of chlorine content increased) to the point that it could not be consumed in the Point Aconi boiler. Finally, supplies from CBDC were unreliable. Problems with geology (roof falls and floods) and with organized labour led to supply interruptions from time to time. However, investigations by NSPI and by proponents considering the purchase of the mines confirmed that the mine could continue to produce at a rate of about 1,000,000 tonnes per year. Throughout the life of the agreement, CBDC took the position that it had the right to import to supply NSPI’s requirements, thereby continuing to employ some of their employees and to use their surface assets (even if the mines were to close). The relationship was a difficult one throughout its life, characterized by acrimonious negotiations, action by unionized CBDC employees, litigation and arbitration. (NSPI, Post-Hearing Brief, pp.14-15)

[60] NSPI argues that it is reasonable to include the annualized cost of the buy-out

in the test year expenses for 2002 (and beyond) since ratepayers got the benefit of a retroactively

reduced coal cost which facilitated NSPI’s ability to continue to defer an application for a rate

increase until late 2001.

Document : 78377 29

[61] Under cross-examination by Board Counsel, Mr. Huskilson elaborated on the

benefit to ratepayers of NSPI’s decision to terminate the contract:

Q. I want to turn now to the Devco buyout. I realize it's fashionable now to refer to it as CBDC, but it's been Devco for long enough in my mind anyway, that I'll refer to it as such. It's established on the record that the agreement for the buyout of the Devco agreement was made in April of 2001. Correct? A. Yes, that's correct.

Q. And as a result of that buyout and the renegotiation, the amending agreement, the coal price that the company paid -- that is, NSPI paid -- was reduced? That's correct? Over the previous level, over the contract ending 1999. A. Yes, that's correct. At the end of 1999, we would have been paying about two dollars and sixty-two cents a million BTU.

Q. And those lower prices that were negotiated in April of 2001 resulted in retroactive reductions in the costs associated with your coal purchases in 2000 and the first four months of 2001. Correct? A. Certainly they had retroactive effect, but certainly at the time, in the year 2000, we wouldn't have known what we were paying. We would have made some assumptions about what that was, but we wouldn't have known what we are paying at that time. That's right.

Q. If I interpret the response to Grant IR -- I guess it is 15.6 -- the savings in 2000 with respect to the reduced coal cost was 14.3 million? A. I think the way I'd characterize that is that the value created against what it otherwise might have been in the year 2000 would have been that fourteen million dollars ($14,000,000). It wasn't actually a savings in that year, though, because of the fact that we didn't know it until after that year ended up closing. So it's -- what the table was doing was trying to represent the value created, but in fact that value was created later rather than -- not in that year.

Q. And additional savings in 2001? A. Again, that would be the value that's created from the analysis that we would have done. I guess what I'd say is it's hard to characterize it as a savings because we didn't know what otherwise it would have been, but it certainly is the value against what it otherwise could have been. And you have to remember that what we were testing it against was an arbitration that might occur which we believed would probably occur in 2002 and which we believed would also probably set prices at or near the higher end of the range as opposed to the lower end of the range. Going into an arbitration where the two sixty-two was the starting point, our expectation would be that we would have seen a higher price than two sixty-two rather than a lower price.

Q. Is it fair to say that the value you speak of was created when the agreement was signed? A. Yes, I would say that that would be fair to say.

Q. And to date, has the renegotiation of the Devco contract resulted in any change in the price of electricity to NSPI customers?

Document : 78377 30

A. I think what it did was it allowed us to not -- so I think if you looked at it another way, you could have said that in the summer of 1999, we were facing a renegotiation with CBDC for the five-year period. Had we believed at that time that in fact we were not going to be in any way successful in anything other than an arbitration -- so in other words, if we weren't working hard to ensure that we could reduce the cost for the year 2000, we would have come to the Board then and said, "We expect coal prices to be, I don't know, three dollars ($3) a million BTU or three dollars and fifty cents ($3.50) a million BTU and we need a rate increase for the year 2000." And so that would have been the approach that we might have taken. So that I would say that in the year 2000, the fact that we took the approach we took with CBDC saved a rate increase in the year 2000 that we could have applied for in late 1999 had we taken a less aggressive approach with the CBDC renegotiation. So that, yes, I would say absolutely this has deferred a price increase to customers in the year 2000 that would have otherwise been brought forward had we taken a different approach. But it was the company's approach to that negotiation and it was the aggressive stance that we took with CBDC that allowed us to ensure that we didn't have to come to the Board and ask for a price increase for the year 2000. So that's a savings that the customer has already seen.

Q. But you'll agree with me, Mr. Huskilson, that customer[s] had no assurance of receiving that saving, nor did NSPI until April 2001. A. Well, the fact that we didn't come before the Board meant that the customer[s] did receive theirs. Absolutely.

Q. But the bottom line is, though, that you didn't know what the outcome of the negotiations were until April 2001. Correct? A. But we could have settled it in -- we could have settled it easily in the fall of 1999. Without any doubt, had we just simply agreed to a high price, we could have settled it, and that would have meant a price increase to customers.

Q. But the bottom line is the negotiation concluded in April of 2001. Correct? A. Absolutely correct. (Transcript, April 29/02, pp. 1097-1102)

[62] In its post-hearing brief, NSPI provided the following justification for inclusion of the buy-out fee in the test year expenses:

When, in the course of negotiations for the renewal of the price and quantity under the agreement, it became possible to amend the agreement to shorten the term and eliminate the issue about coal importation, NSPI decided to proceed. In return for a payment of $13.4 million, NSPI achieved a number of things: a) A price for the years 2000, 2001 and 2002 which was lower than the price which had prevailed in the past. NSPI’s assessment was that this price was favourable in that it was lower than the price that might be awarded by an arbitrator under the four factor formula. b) A shortening of the term of the contract from 2010 to 2005. New environmental limits coming into effect in 2005 would have made significant investment in scrubbers necessary in order to continue burning Cape Breton coal, while use of lower sulphur (or high sulphur/low chlorine) imported coal would be possible without the cost. c) Elimination of the possibility of importation by CBDC to supply NSPI.

Document : 78377 31

d) Clarity as to volumes and quality of coal. e) The right to acquire the surface transportation assets, including the international coal pier in Sydney and the CBDC railway at fair market value. Each of these provisions was of great value to NSPI and its utility customers, both at the time and in the future. It cannot be seriously suggested that the buy-down of the agreement was not reasonable and prudent, in the interest of NSPI and its customers, at the time it was made. (NSPI, Post-Hearing Brief, pp.15-16)[Emphasis in original]

4.2.2 Submissions - Intervenors

[63] The intervenors generally agree that NSPI should not be permitted to recover the cost of the CBDC buy-out. SEB and Annapolis, whose expert witnesses examined the confidential documents including those pertaining to the CBDC buy-out, provided the most extensive arguments against allowing NSPI to recover the costs. As noted earlier, much of this information has been filed in confidence. In the redacted version of her direct evidence, Ms. Medine testified that NSPI should not be allowed to recover this cost, stating that:

1. NSPI did not need to pay CBDC for an early termination of the Agreement because: · CBDC was not going to be around and CBDC did not have the right to unilaterally assign the Agreement to a third party. · NSPI already had early termination rights under the Agreement that it could have utilized.

2. The NPV analysis was flawed and grossly overstated the potential savings tied to the early termination payment. · Ratepayers did not derive any benefit from the retroactive establishment of the C$2.11 per MMBtu price in 2000 and 2001. · The presumption that regardless of the import price, CBDC would be C$0.28 per MMBtu higher is without analytical justification and was inconsistent with actual prices in 2001. · CBDC coal could have burned in 2005 under the current environmental requirements without scrubbing and there is no guarantee that Lingan will not have to be scrubbed in any event.

3. To the extent that NSPI realized lower prices in 2000 and 2001, as a result of the payment, NSPI has already recovered the payment by virtue of the lower prices as reflected in NSPI’s own net-present value analysis. (Exhibit N-39, p.16)

[64] Ms. Medine elaborated on her reasons for this view during the in camera

Document : 78377 32 session before the Board.

[65] In the redacted version of her direct evidence, Ms. Hennings also indicated

that, in her opinion, NSPI should not be allowed to recover the buy-out costs. She stated that:

NSPI should not be allowed to recover the cost of the buyout in 2002 and later years. It should be granted no regulatory asset for the buyout costs. The cost of the buyout has already been recovered in the price reductions under the buyout contract for NSPI’s coal purchases in 2000 and 2001. NSPI paid only part of the invoiced price of its CBDC coal receipts, starting in 2000. NSPI made a lump sum payment of the difference between its partial payments and the revised amounts due under the buyout as part of the buyout settlement in late 2001. In effect, it received the cash from the price reductions as the coal was delivered in 2000 and 2001. By 2002, NSPI’s benefit from the buyout became a loss due to market price changes in other coal transactions and a lack of term contracts. CBDC closed its mine and no longer supplied the coal savings that supported the buyout price. NSPI’s actual coal prices for 2002 would be higher than the 2002 CBDC coal price would have been without the buyout. If the buyout had not already been recovered by 2002, the prudence of the buyout could have come into question because NSPI did nothing to hedge the future market price used in its analysis.

8. Do you have any additional comments about the buyout analysis? Yes, I think NSPI incorrectly included the avoided price of scrubbers for two units at the Lingan plant in its analysis. These scrubbers and other capital equipment may still be necessary to avail NSPI of the lowest coal prices. Capital equipment investments may allow NSPI to burn a wider variety of coals, some of which are more competitive than coal from the markets NSPI currently uses. (Exhibit N-30, pp.3-4)

[66] Annapolis takes issue with the inclusion of the buy-out fee, arguing that:

NSPI’s character is revealed in its requests to recover from the ratepayers the “termination fee” paid by it as part of its settlement with Devco for its disputed values of delivered coal. The evidence on record leads to the inevitable conclusion that the “termination fee” was a device proposed by NSPI to enable it to support the $2.11 per MMBtu at which it booked Devco coal in 2000. Based on this booked price, NSPI’s shareholders would enjoy dividends and its executives their bonuses. From Devco’s perspective, it did not matter how this payment was characterized as long as the cumulative payment under the Amending Agreement gave it a fair price for the coal which was already delivered. The proximity of the announcement of the closure of the Prince Mine to the conclusion of the Amending Agreement and the absence of a covenant to continue to produce the coal can leave little doubt that the negotiated price was never intended by Devco to have a prospective effect apart from coal which it could “high grade” from the already developed face. The treatment of interest under the Amending Agreement illustrates that the “termination fee” was made as part of the compromise payment respecting the disputed invoices, the benefits of which NSPI has already enjoyed. NSPI’s attempts to withhold the contemporaneous analysis of the benefits of the Amending Agreement to NSPI and to proffer instead an after-the fact analysis which includes different calculations than presented to its Board of Directors does not reflect well upon NSPI and illustrates the extent to which an attitude of “putting it to the ratepayers” has infused the organization. (Annapolis, Closing Brief, pp.4-5)

Document : 78377 33

[67] SEB made similar arguments against NSPI including the buy-out cost in its revenue requirement in its confidential closing submission to the Board on fuel costs. The Province made the following objection to the inclusion of the buy-out fee:

NSPI are seeking approval of the Board to amortize the $13.4 million CBDC Contract termination fee over a five year period beginning in 2002. In response to Grant IR 15.6, NSPI provided a net present value calculation of the CBDC termination fee showing an approximate net present value of $144.4 million. Ms. Hennings in Exhibit N-3 and Ms. Medine in Exhibit N-39, both concur that the cost of the buyout has already been recovered in the price reductions for NSPI’s coal purchases in 2000 and 2001 under the CBDC Amending Agreement of April 2001. It is submitted that the termination fee paid by NSPI should have been fully charged in 2001 when the company realized the fuel savings for both 2000 and 2001. The termination fee was simply a substitution for a decreased fuel cost in 2001. (Province, Closing Submission, p.14)

[68] ECANS and MEUNSC also indicated to the Board that, in their view, NSPI

should not be allowed to recover the cost of the CBDC buy-out.

4.2.3 Findings

[69] The Board has reviewed the explanation offered by NSPI witnesses with respect to the basis for inclusion of this expense and the reasoning and analysis that ultimately persuaded the Board of Directors to approve the contract buy-out. There was considerable discussion at the hearing regarding the nature of the long term CBDC contract, i.e., whether it actually was a requirements contract. It is noteworthy that, despite NSPI’s characterization of the contract as a “requirements” contract, and CBDC’s assertion that it could import to supply NSPI,

NSPI did acquire coal from sources other than CBDC while the contract was still in effect.

[70] The Board notes that under cross-examination, Michael O’Neill, NSPI’s Vice

President of Finance and Administration, confirmed that the April 2001 buy-out established a coal price of $2.11/MMBtu, which was the same amount recorded four months earlier, in December of

Document : 78377 34

2000, when NSPI booked its 2000 coal price in its year end accounting records.

[71] With the exception of Mr. Watkins, all of the experts who reviewed this

matter - Ms. Medine, Ms. Hennings, Dr. Rosenberg and Dr. Stutz - agree that the expense associated with the termination fee should be disallowed. In response to a question from the Board concerning whether he agreed with Ms. Medine that the buy-out fee should be excluded, Dr. Stutz responded that:

I do. And I'd just like to turn up something and then I'll answer. What I'm looking at is a table that appears at the end of Grant 15.6. And there's no need to go rooting around for this table, but if you look at Grant 15.6, there is a calculation which shows the costs and benefits of termination. And on its face, what it shows is that there was a net benefit at the end of 2001. So one of the things that I believe Ms. Medine said was that the benefit was there already and the costs had been effectively recovered. Then you went on to talk about intent. I find it difficult to address intent. We have the product here of a settlement of some sort, and knowing what went on in the settlement is very difficult. But we certainly can look at effect, and what we know is that a relatively low price, two dollars and eleven cents ($2.11), was imputed for 2000 and 2001. Certainly everything I've heard suggests that if this buyout hadn't worked, we would have been paying more than that. So you got a relatively low imputed price and you have a balloon payment. Now, as a matter of arithmetic, you could increase the price and get rid of the balloon. There may be some reason why Devco would prefer the balloon, but it's very hard for me to imagine it, and I certainly didn't hear it in the time I was here. Now, during the years when we've imputed these prices, it also appears to me from the indexed data that was used on cross-examination that appears in one of the IRs that the company was earning at or a tiny bit above its allowed rate cap of 11 percent. So I think her point that in fact the result was that the company had already been paid is supported. Whether the company in fact organized its negotiations to prove that -- to provide that result or whether it just fell out that way, I can't say. (Transcript, June 4/02, pp. 3985-3986)

[72] Notwithstanding the evidence of NSPI witnesses, the Board finds it difficult to

discern a future benefit to ratepayers as a result of a fee paid to terminate a coal supply contract

approximately one month before the announcement was made that coal mining by CBDC would

cease. In any event, the Board finds that, based on the evidence, it is reasonable to conclude that the

benefits of the $13.4 million paid to terminate the CBDC coal supply contract have already been

realized by shareholders. Under these circumstances, it is not appropriate to transfer the burden of

this fee to the ratepayers. Accordingly, the proposed expenses associated with this fee are

Document : 78377 35 disallowed. Test year expenses will be reduced by $2.7 million, which is the amortized value of the fee for 2002.

4.3 January Adjustment

4.3.1 Submission - NSPI [73] As noted earlier, NSPI filed its application for a general rate increase on

December 18, 2001, using 2002 as the test year. In a letter dated January 28, 2002, NSPI updated

the December 18, 2001 filing.

[74] NSPI’s January 28, 2002 letter reads as follows:

In its prefiled evidence of December 18, 2001, NSPI undertook to file updated 2002 financial forecasts with the UARB on January 28, 2002, even if no change to revenue requirement is warranted (page 16, lines 7-8).

NSPI has completed its update. A summary of revisions to the forecast is as follows:

Adjustments $ millions

1. Fuel (net of reduced export revenue) -13.4

2. OMG 6.1

3. January Revenue Deficiency 5.0

4. Interest Expense Increase 0.2

5. Revision of Revenue From Annually 4.2 Adjusted Rates

6. Income Tax Reduction -3.1

7. Test Year change in Earnings 1.0

Net Adjustment 0.0

1. Fuel costs have decreased from $372.0 million to $354.8 million. This is due to a higher inventory of CBDC coal than expected at the end of 2001 and a modest decline in world coal prices. It also reflects updated fuel prices. Export sales revenue has been reduced by $3.8 million due to the lower fuel costs. 2. The operating, maintenance and general expense has increased by $6.1 million. This includes a reduction in Power Production OM&G of $0.3 million and an increase in pension expense of $6.4 million due to a change in actuarial assumptions reflecting market conditions. 3. Sales and revenue have been updated to reflect January, 2002 estimated results

Document : 78377 36

including warmer weather. 4. Interest expense has increased slightly due to timing changes in cash flows. 5. Annually adjusted rates for 2002, as submitted to the UARB on November 20, 2001, are being revised to reflect the changes, since they are formula driven. These are being submitted to the Board under separate cover. The impact of the annually adjusted rate revenue is a function of when other proposed rates are approved. This is because the Industrial Expansion rate is capped by the Interruptible rate. The impact shown assumes the increases requested in the current application become effective May 1, 2002. 6. Income tax has changed due to a revised 2001 closing taxable position.

The update confirms the 2002 forecast originally filed. We are, therefore, still seeking approval of the rates as proposed in our December 18, 2001 filing.

Given the changes which have occurred, NSPI is hereby filing: a) Updated financial tables (Tables 3.1R to 3.13R) for 2002. b) An updated load forecast table (Table 4.1R) reflecting the January 2002 impact. c) Table A showing that the impacts of these changes on Revenue/Cost ratios are minimal.

(Exhibit N-160)

[75] In response to questions from Counsel for SEB, Mr. Huskilson gave the following explanation for the filing of the January adjustment:

Yes, we -- the primary concern that we had about our filing that we made on December 18 was that we -- it was going to be very hard for us to predict what our closing inventory levels would be, and because we believed that we might still have some lower-cost coal on the ground we believed that it would be very important to make sure that, that update be reflected. And as I stated earlier, that was one of the corrections that we believed to be important to make in order to ensure that we were asking for a revenue requirement that was most appropriate and reflected all of the changes that we could envision in our fuel forecast. (Transcript, April 22/02, p.47)

[76] In its reply brief, NSPI points out a lack of consistency in intervenors’ arguments on this subject stating that:

NSPI has attempted to put forward the most accurate forecast of the test year of 2002 possible. In doing so it has incorporated actual data to the extent it is available. NSPI has incorporated actual data which is favourable and unfavourable. The intervenors attempt to rationalize their proposals to include the unfavourable data while excluding the favourable data. (NSPI, Reply Brief, p.1)

[77] NSPI witnesses indicated that the purpose of the January 28, 2002 letter was to provide to the Board information which might be of assistance in considering the rate application in view of the timing of the hearing and “actual” data relating to the test year. Subsequent to filing

Document : 78377 37 the January 28, 2002 letter, NSPI filed amendments to its direct evidence, including revised financial tables, which reflected the noted changes.

4.3.2 Submissions - Intervenors

[78] Virtually all of the intervenors disagree with some component of the January

adjustments. In particular, the intervenors object to the weather adjustment, which is item 3 in the

January 28, 2002 letter. This change incorporates the inclusion of “actual” January 2002 weather

data in the test year. In his direct evidence, Dr. Rosenberg opposed NSPI’s adjustment to its revenue

requirement based on a warmer than normal January. Dr. Rosenberg asserts that:

. . . When NSPI made its initial filing it based its forecast on normal weather. This is as it should be. When forecasts are based on normal weather the expected value of sales will be equal to the forecast. While actual results will almost always differ from forecast, the forecast is at least what a statistician would call “unbiased”. However, by taking a single month and using abnormal weather, while at the same time using normal weather for the remaining 11 months, NSPI has biassed its forecast. Now if NSPI could present conclusive evidence that the balance of the year will not be colder than normal (or that January 2003 will not be colder than normal), it might have a point. Of course it is unable to present any evidence, so the January adjustment must be rejected. (Exhibit N-113, pp.27-28)

[79] In his opening statement, Dr. Rosenberg again referred to NSPI’s January

adjustment stating that:

The last item concerning NSPI's revenue requirement that I address is the so-called January adjustment. The net result of this adjustment, as Mr. Whalen concedes, would be to base rates on a test year that was warmer than normal, contravening a fundamental precept of regulation, and this adjustment should be summarily rejected. (Transcript, May 24/02, p. 3508)

[80] Dr. Stutz, in his direct evidence, also opposed the use of “actual” weather

results stating that:

Actual January data are unrepresentative because the weather in January was much warmer than normal. As stated in NSPI’s response to NSUARB-IR-342, heating degree days for January 2002 were 628, while normal is 702. As noted in NSPI’s response to NSUARB-IR- 241, the warm weather in January reduced sales substantially. If test year data are to be

Document : 78377 38

representative, they should reflect normal weather for January. NSPI’s forecast data does that. (Exhibit N-152, p. 15) [81] Under cross-examination by NSPI Counsel, Dr. Stutz commented on the question of adjusting test year data with actual data. The following exchange is illustrative:

Q. All right. Looking -- talking about other things that may or may not be ignored, and that is the actual data for January. A. Yes.

Q. And you've offered the opinion that the actual data for January should not be relied on. A. That's correct.

Q. Are you looking only at the weather data or are you looking more generally at actuals of other things. A. No, I don't think you should use the actuals at all, and the reason is basically that you need a consistent test year, and you have a consistent test year based on normal weather and all your other assumptions.

Q. We know that the demand was down in January and that weather was just one factor that contributed. Should we ignore all the other factors as well? A. Yes, because again you're trying to set the rate -- well, let me say it a different way. The rates you're setting will be used -- could be used for some January, but it's not the January you have data for. It's the January in the future. And there's no particular reason to think that this January would be similar to a future January, and in fact, your own heating degree data suggests it won't be at least in that score.

Q. So would you equally ignore actual cost impacts -- the cost impacts -- the costs to the company should also be based on forecast rather than actuals? A. I think you have to have a consistent set of data. Okay? And I think your January adjustment makes your data inconsistent. (Transcript, June 3/02, pp.3788-3789)

[82] Dr. Stutz also gave the following response to a Board question:

It's still a future test year, right, because it doesn't have all historic data. You could call it a mixed test year if you want to be precise. But I focused on the forecast information as the one area in which I felt the update simply could not be accepted, and in my testimony I gave one reason. I think this was brought out on cross-examination, perhaps by Mr. Cooper, but the key point is that we're, in effect, forecasting warmer than normal weather if we average in the January sales. And that just isn't reasonable. You're looking out prospectively. Januarys are not always warmer than normal. If you look at the IR response that shows heating degree data, you'll discover that January of 2001 was about spot-on for average weather. So, it's simply not reasonable to use warmer than normal data. Moreover -- and this is something I said to Mr. Campbell and I'm not sure I was completely clear about this -- putting in a month of actual weather makes a shambles of the entire analytical framework, because the way the analytical framework is constructed is there's an annual forecast of sales, that forecast is then divided into monthly data and the monthly data is used in a variety of places including the cost-of-service study. Now, you can't simply carve out a little piece of the annual sales data, drop in January and have anything make sense. You're then -- when

Document : 78377 39

you're putting together your analysis, if you're taking annual data which includes the old January and allocating it, the February data that you've got in there, in effect, reflects the aggregate and so the old January but you've got it sitting next to the new January. Moreover, everything you've done reflects normal weather except for the new January where the heating degree days were more than 10 percent different from normal. It's chaos. You just can't do that. So, for the two reasons, the representativeness and the chaos avoidance, if you will, I think you have to reject the use of the January data. Now, does that mean you reject the entire update? No. You simply use the update without the January data. (Transcript, June 4/02, pp. 3935-36)

4.3.3 Findings

[83] The Board agrees with the views of the intervenors with respect to the

problems which would occur if actual weather data for January 2002 was incorporated into the test

year calculations. The Board finds that mixing actual and projected weather data is not a sound basis

for rate-making. Indeed the Board finds that the January 28, 2002 update, with respect to all the

items, not just the weather adjustment, should be disregarded by the Board in determining the

appropriate revenue requirement for NSPI.

[84] The Board believes that the December 18, 2001 filing by NSPI represented the

Utility’s best forward-looking estimate of the 2002 test year. The Board agrees with Dr. Stutz’s

point that incorporating "actual" January data may have the effect of lessening the consistency and

reliability of the test year data.

[85] If the rate-making process were based on the most up-to-date numbers, as

opposed to forward-looking data derived from experience over the longer term, each month could

bring innumerable changes to the revenue requirement. On balance, it is the Board’s view that this is

not an appropriate methodology to employ for rate-making purposes. Therefore, despite the appeal

of "actual" results over projections and the arguments which have been made with respect to all or

Document : 78377 40 some of the adjustments, the Board has decided to disregard the January filing. Accordingly, the

Board will consider the test year data included in the original filing by NSPI dated December 18,

2001. The Board notes that, in any event, the net effect of the January adjustments on NSPI’s projected revenue requirement is zero.

4.4 Hydro

4.4.1 Submission - NSPI

[86] NSPI, using five year average rainfall data, projected a reduction in hydro

generation over previous years. Since there is little or no fuel required in hydraulic generation, a

decrease in this cheaper form of power production results in higher fuel costs. In previous filings

before the Board, NSPI used a twenty-three year average to predict rainfall with the result that hydro

generation was higher than is estimated in the current application.

4.4.2 Submissions - Intervenors

[87] Ms. Hennings, in her direct evidence, made the following observation

concerning NSPI’s estimate of hydro generation:

My first adjustments, a fuel cost reduction of $[redacted] million, changes the plant dispatch from what was forecast by NSPI. This reflects an increase of 80,500 MWh in the 2002 forecast of hydraulic generation. The revised hydro generation forecast is equivalent to a 23- year average of the actual NSPI generation that was provided in response to SEB IR-15. NSPI’s 2002 hydraulic generation estimate is based on a 5-year average, with the generation effects of hurricanes removed. Removing the effects of hurricanes tends to understate the resource. Using a long period of historical information can smooth out differences between estimates and actual generation. Data from a long history should be adjusted for capacity changes during the history. NSPI’s hydro capacity was not increased or decreased during the 23 years given in NSPI’s response, so I used a simple average of the 23 years history. I decreased the forecast generation from NSPI’s oil fired combustion turbines by 25,000 MWh. According to SEB IR-10, the average increase for the last 3 years of combustion turbine generation was 20,000 MWh per year. This year, the forecast increase over 2001 annualized

Document : 78377 41

information is an increase of 45,000 MWh from 2001 data. My adjustment brings the 2002 increase into line with prior years’ rate of change. It also reflects the replacement of marginal system energy with part of the adjustment for increases in hydraulic power. When combustion turbine generation runs, it is often on the margin. The remaining energy reduction of 55,500 MWh is assumed to come from high cost coal generation.

These energy adjustments are calculated to decrease total fuel costs by $[redacted] million. The assumptions used for average fuel costs of each of the sources of energy were that hydro power is provided at no fuel cost, combustion turbine energy is assumed to average $[redacted] per MWh, and Tuft’s Cove energy is assumed to average $[redacted] per MWh, according to NSPI’s filing. (Exhibit N-30, p.9)

[88] Ms. Hennings was cross-examined by Counsel for NSPI on this issue during

an in camera session and, therefore, the Board is constrained from reproducing that exchange in this

decision. However, it can fairly be said that, while NSPI challenged Ms. Hennings’ assumptions

relating to marginal fuel costs, it did not directly contest her hydro generation based on a twenty-

three year average. In the confidential annex to its post- hearing brief, NSPI defends its estimate of

hydro based on rainfall averages of recent years as opposed to long-term rainfall averages. NSPI

further asserts that, even if the Board was inclined to adopt the long term data, Ms. Hennings’

adjustment would also change the dispatch model and should not be accepted without an off-setting

costing which would incorporate the impacts of dispatch changes.

[89] SEB counters, in its confidential closing submission, that since there is no fuel

cost component to hydro generation, when hydro displaces fuel-driven generation, it follows that fuel

costs are reduced. SEB argues that this occurs regardless as to what dispatch model is used to run

numbers.

4.4.3 Findings

[90] The Board notes that this issue was canvassed in UARB IR-130(A). NSPI

Document : 78377 42 was asked to estimate avoided fuel costs if assumed hydro generation in 2002 was at a higher level.

NSPI, in its response to UARB IR 130(A), stated that:

IR-130(A) To estimate the impact of reducing hydro generation from 991 GWh to 917 GWh for the year, the Proscreen model was re-run changing only the assumption about hydro production volumes. The effect of increasing hydro generation was to decrease total fuel costs by approximately C$3M. (NSPI response to UARB IR-130(A))

[91] It is reasonable, in the Board’s opinion, to use a twenty-three year average for

hydro generation rather than a five year average. The twenty-three year average is used by NSPI in its weather data and has been used in its economic analysis methodology in other filings with the

Board. In any event, absent convincing evidence to the contrary, the Board believes longer term data is preferable for purposes of estimating hydro generation.

[92] Using the information provided in NSPI’s response to UARB IR-130(A), the

Board finds NSPI’s avoided fuel cost as a result of increased hydro generation to be $3 million.

NSPI’s test year expenses will be reduced accordingly.

4.5 Compensation

4.5.1 Submission - NSPI

[93] NSPI, in its direct evidence, requested that the Board allow the inclusion of

100% of incentive compensation/bonus costs in the 2002 test year expenses. NSPI acknowledged that this constitutes a change from the 1996 Board decision when only 50% of incentive compensation was permitted to be included in the test year expenses.

[94] NSPI asserts, notwithstanding the Board’s finding in its 1996 decision, that:

Performance based compensation is not an amount in addition to employee compensation - it forms part of the fair and reasonable compensation of an increasingly large portion of NSPI’s work force. NSPI’s employee compensation levels, including performance-based compensation are “mid-market” as compared to levels for comparable staff in other large

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organizations. NSPI operates in a very competitive market for executive, managerial and staff talent, and a compensation package incorporating an incentive element is considered a requirement to attract, retain and motivate qualified employees. These amounts are reasonably and necessarily expended in the operation of the utility and should form part of the Company’s revenue requirement. The alternative would be to eliminate the incentive program and adjust base compensation. This, however, would not be in the interest of either customers or investors. Payment of incentives is contingent on employees meeting objectives aligned with NSPI’s corporate objectives. Evaluation is based on a Balanced Scorecard which recognizes the interests of customers, employees and investors. This encourages innovation and excellence and performance by plan employees, to the benefit of all stakeholders - payment is neither automatic nor guaranteed; for 1998, no incentives were paid to any employees. NSPI has included in its 2002 revenue requirement 100% of incentives totalling $3.5 million;

2001 projected results include one-half of the incentive at $1.6 million. Given the benefit of

the program, NSPI respectfully requests that the Board reconsider this issue and include

100% of the incentive as part of the revenue requirement.

(Exhibit N-1, pp.18-19)

[95] In Exhibit N-1, p.2 of Appendix 1, NSPI submits the following 2002

compensation cost for its Executive Management:

Thousands of $ Executive Management

Actual Forecast Change Percentage Forecast Change Percentage 2000 2001 from change 2002 from Change 2000 2001

Total Operating Labour 1,524.0 1,975.1 451.1 30% 2,081.3 106.2 5% (Exhibit N-1, Appendix 1, p.2)

[96] In Undertakings U-9 and U-10, NSPI provided information concerning the process for determining appropriate levels of compensation for senior management and the bench- marking with comparable utilities and other companies that is done in setting compensation levels. NSPI did not provide any specific support in its pre-filed evidence for the proposed expenses relating to compensation for Executive Management.

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4.5.2 Submissions - Intervenors

[97] Several intervenors, notably Annapolis, HRM, ECANS and the Province, took

issue with the level of compensation paid to Executive Management.

[98] Counsel for Annapolis introduced Exhibit N-18, which reflects information

contained in management information circulars attached to NSPI’s responses to UARB IRs 215 and

166. The table compares compensation paid to senior NSPI management at the time of the last rate

hearing to present day compensation levels. (See the Table of Salaries on the following page).

Table of Salaries

President and Chief Executive Officer - Louis R. Comeau; David Mann (from 1996) * Annual base for 1996

1993 1994 % 1995 % 1996 % 1997 % 1998 % 1999 %

Change Change Change Change Change Change

Salary 157,212 165,621 185,287 325,000 335,521 346,535 358,792

Bonuses 40,640 43,890 42,185 25,000 65,000 180,000

Other

Total 197,852 209,511 6% 227,472 8.5% 350,000 54% 400,521 14% 346,535 (-13%) 538,792 55.5%

Christopher G. Huskilson - Executive Vice-President Operations/Chief Operating Officer Nova Scotia Power Inc.

1993 1994 % 1995 % 1996 % 1997 % 1998 % 1999 %

Change Change Change Change Change Change

Salary 111,547 140,077 178,654

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Bonuses 13,300 39,590

Other

Total 124,847 140,077 12% 218,244 56%

NOTE: Correction - Transcript, April 23, p.317 which reads:

(Exhibit N-18) “ . . . there's a small typo in the fifth column for 1995 for the President and CEO. It should read "227,472."

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[99] In its closing submission, Annapolis stated that:

It was clear from the evidence that there has been a substantial increase in executive compensation between 1993 to 2002 with the President’s salary and bonus increasing from about $200,000 to over $830,000. The Vice-President showed an increase of over 56% just from last year (Exhibit N-18). NSPI has an executive compensation committee to set its management compensation and, while the panel denied that there has been a change in approach, it was apparent from the Management Information Circulars that the bench- marking of salaries to Atlantic Canadian companies has been eliminated in 2002 (Transcript, pp. 322-325). NSPI offered up in response to Undertakings U-9 and U-10 a review of executive compensation. It is significant that in the sample of nine electric utilities and energy companies, when total compensation was divided by total revenue generated, Emera ranked second. While Emera purports to be global and diversified, NSPI remains a mid-size regulated Nova

Scotia utility. Its President was drawn from a local law firm and its Chief Operating Officer is

a Nova Scotian who worked his way up through the ranks of the utility. Should this Board

determine these compensation packages are not reasonable or fully used and useful, it may

disallow some portion of the executive compensation claimed. It is, of course, no concern to

the ratepayers or the Board how Emera wishes to compensate its executives.

(Annapolis, Closing Submission, pp.43-44)[Emphasis in original]

[100] ECANS also took issue with executive management salaries pointing out that, in its view, NSPI’s executive compensation is excessive given the size of NSPI. ECANS also made the point that what is at issue is not the compensation level per se but the amount which is ultimately recovered from utility ratepayers.

[101] HRM registered its objection to the levels of compensation paid to executive management noting that:

Mr. Huskilson in explaining the changed criterion stated that “Emera as an organization is changing”. If the type of salaries needed to reflect the parent’s interest in growth and acquisition is what is driving the common NSPI/Emera Board to so dramatically increase executive salaries, rather than the business reality of NSPI, then only a just and reasonable executive salary cost for the management of a regulated utility should be considered in determining the NSPI revenue requirement. It is submitted that the NSPI/Emera Board has not adopted an appropriate criteria for determining NSPI executive salaries, and, as a result, only a portion of the current salary base including bonus money and other benefits of its top 5 executives should be included in the revenue requirement.

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As a percentage of revenue, both the salaries of the CEO and COO rank as No. 2 and are thus leading salaries relative to revenues not only in Nova Scotia but also among Canadian utility companies. (HRM, Written submission, p. 21) [102] On the issue of incentive compensation, HRM argues that:

There is no evidence on the record from NSPI to support any change from an equal division

of corporate incentives as was ordered by the Board in its 1996 decision. Based on Chris

Huskilson’s testimony that there is a benefit to both shareholders and ratepayers which is

difficult to allocate between the two, and equal allocation of incentives between ratepayers

and shareholders would appear to continue to be appropriate.

(HRM, Written submission, p. 25)

[103] In his direct evidence Dr. Stutz made the following comments on the issue of incentive compensation:

In the past, the Board has allowed only 50 percent of these costs. NSPI states, in response to NSUARB-IR-72, that its incentive plans align individual activities with corporate objectives. As indicated in NSPI’s response to NSUARB-IR-73, these corporation objectives include asset growth, which clearly benefits shareholders. As shown in the data provided in Exhibit JS-6, incentives are a growing part of NSPI’s compensation to top management, which is likely to be knowledgeable about, and concerned with, shareholder interests. Taking all of these point into account, I recommend that the Board continue to allow only 50 percent of incentive compensation costs in NSPI’s required revenues. (Exhibit N-152, pp.15-16)

[104] Under cross-examination by NSPI counsel, Dr. Stutz said:

I think where you have corporate goals that benefit both shareholders and rate payers and where you have compensation tied to those goals and objectives, you have a situation where the shareholders benefit directly and the rate payers benefit directly and it's up to the Board to decide how much of that component of compensation ought to be borne by those who benefit. (Transcript, June 3/02, pp. 3794-3795)

[105] When questioned by the Board, Dr. Stutz said:

The short answer is I'm where I started. Let me address the points that you've raised. Let me begin with the second point. I don't understand anyone, including the Board in its past decisions, to say that the company can't pay incentive compensation. I didn't see anything in there that addressed whether that was -- whether the company could do it. I don't even recall a comment about whether it was appropriate. The issue seemed to go to who benefitted and, therefore, who should bear the cost, and that was the way I approached the issue. The key new information that I heard in this hearing was, in fact, that it's impossible to determine the proportion of benefits. I think that's what Mr. Huskilson said in his cross- examination, that there was agreement that there were benefits to both shareholders and customers but

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that we couldn't determine the percentages, that it was kind of an inseparable cost, if you will. So, we couldn't determine it was 60 percent to one and 40 percent to the other or vice versa. So, 50/50 is a usual choice when you have a benefit that you can't divide, so I don't see any reason for you to change that. As to the question of how many of the staff receive incentives and what the incentives actually incent them to do, I don't see any basis for change there. On the numbers, if you look at my Exhibit 6, you'll see that while larger numbers receive the incentives, the incentive payments in dollar value do tend to be more at the top than uniformly spread. So, there is some reason to believe that the big incentives, if you will, are going to those who might have the interest of shareholders more clearly in mind. However, conscious intent to help the shareholders is not really the issue. If you reduce costs between rate cases, you help shareholders. That's the way regulation works. Because the rates are fixed, if the costs go down, all else equal, the earnings go up. So, over the long haul, because most years you're not setting rates, cost reductions most of the time benefit shareholders, not ratepayers. Now, I think that's appropriate. I think it gives the company a real incentive to do better. So, I don't object to that. I think it's a fine feature of regulation. But it does mean that things you do, even customer service, for example -- suppose you keep a customer happy and so he doesn't, in a fit of peak [pique], go out and buy his own generator. Between rate cases that helps the company. So, I think all of these things that were said are true, but I think they all, in many instances, help the shareholders. I think they also help the ratepayers in the long run, because in the next rate case they have a bigger base over which to spread their revenue. So, I'm not arguing one against the other, I'm simply supporting, I think, your earlier finding that both benefit. (Transcript, June 4/02, p. 3924-26)

4.5.3 Findings

4.5.3.1 Executive Compensation

[106] The Board is concerned about the rapidly increasing compensation which is being paid to the executive management of NSPI and which is included in costs to be recovered from ratepayers. Other than providing information and assurances that compensation is “bench-marked” against comparable positions, NSPI has not, in the Board’s view, adduced any justification for ratepayers to bear these increased costs. In Exhibit N-18, it is clear that the compensation costs for

NSPI’s two most senior executives have increased dramatically over the past several years. The

Board has no information regarding the compensation of other senior executives of NSPI so its comments in this regard refer to the individuals noted in Exhibit N-18.

[107] The compensation paid to management is the prerogative of the Board of

Directors which is accountable to the shareholders of the Company. Obviously, the NSPI/Emera

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Board of Directors, acting on behalf of shareholders, believes these salaries are justifiable and competitive.

[108] The Board does not believe current compensation levels are acceptable to the

vast majority of ratepayers in this Province. This sentiment is clearly expressed in a number of the

comments made to the Board, particularly during the public evening session on April 25, 2002. The

issue of dramatically increasing compensation is exacerbated by the knowledge that these individuals

do not work exclusively for NSPI, as they also have responsibilities relating to other Emera corporate

activities. That being the case, the Board is of the view that it is appropriate for the shareholders to

bear a significant portion of the increased compensation costs.

[109] It should be noted that in 1996 there was a different management structure in

place at NSPI. Today there is a President who is the Chief Executive Officer, and also a Chief

Operating Officer, a position that did not exist in 1996. It appears to the Board that Mr. Huskilson is the individual in charge of NSPI operations on a day-to-day basis. He appears to be discharging many of the duties previously performed by NSPI’s President. This is evidenced by his appearance as the most senior executive of NSPI present during the hearing.

[110] The Board believes it is fair for ratepayers to bear compensation costs that

have increased at a reasonable rate from those paid at the time of the last rate hearing. Using the

President’s 1996 compensation as a base, the Board notes that Mr. Huskilson’s current compensation

of $483,669 represents approximately a 38% increase over that paid in 1996.

[111] The Board was impressed by Mr. Huskilson’s knowledge of NSPI affairs, as

he was questioned during the hearing about a wide range of NSPI matters. It is clear to the Board

that Mr. Huskilson devotes much of his time to NSPI activities. With respect to the compensation

Document : 78377 50 paid to Mr. Huskilson therefore, while the Board has some concerns about the magnitude of the amount, as well as about the significant increase during the last few years, the Board is prepared to accept it as a reasonable reflection of his contribution to NSPI. Accordingly, except for the incentive

compensation and corporate support allocation discussed below, the Board is prepared to include Mr.

Huskilson’s full compensation in the revenue requirement for the test year.

[112] The Board has some satisfaction that Mr. Huskilson’s salary is not completely

out of line compared to other Atlantic Canadian companies. The figures in Undertaking U-10 show that for three Atlantic Canadian companies the average total compensation for the president is approximately .06% of revenue. If this percentage is applied to NSPI’s revenue, the result approximates the compensation Mr. Huskilson is receiving. The Board puts more weight on the

Atlantic Canadian companies primarily because they are in the same region as NSPI which provides a more meaningful comparison, and also because the other companies listed in Undertaking U-10

are significantly larger than NSPI in terms of revenue. The Board recognizes that the figures used in

the calculation of the Atlantic Canadian percentages are primarily for the respective presidents.

However, the figures for the Vice-Presidents are not given in all cases, and further, the Board is of

the view that Mr. Huskilson appears to perform many of the duties of a president.

[113] Accordingly, for the purpose of test year expenses, the Board accepts the

compensation paid to Mr. Huskilson with the understanding that the allocation of the costs of his

compensation between NSPI and Emera (which will be discussed later in this decision) will be

applied to, and further reduce, the revenue required from ratepayers, as will the Board’s ruling on

incentive compensation.

[114] With respect to the compensation paid to David Mann, President of NSPI, the

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Board has no evidence before it of Mr. Mann’s duties with NSPI. There were references at the hearing to the fact that Mr. Mann did not give evidence during any of the proceedings. While his absence is not unprecedented, it does leave the Board with no evidence on the record of Mr. Mann’s day-to-day activities and, consequently, scant support for charging to ratepayers a 73% allocation of his $832,000 annual compensation package. The evidence which is before the Board would seem to indicate that many of Mr. Mann’s activities primarily relate to Emera. As President of Emera, Mr.

Mann heads some 15 of the 42 companies which fall under the Emera umbrella, including NSPI.

[115] Without having any substantive evidence to support the reasonableness of Mr.

Mann’s current compensation level in relation to his duties and responsibilities with NSPI, the Board can only conclude that the ratepayers are being asked to bear compensation costs, a significant portion of which are primarily for the benefit of the shareholders of Emera. It is clear to the Board that Mr. Mann, as President of NSPI, is ultimately responsible for the operations of the Company.

However, the Board is left with the impression that much of Mr. Mann’s time is spent on the activities of Emera and its 42 affiliates. Accordingly, in the absence of any evidence to the contrary, the Board will disallow one-half of the cost of Mr. Mann’s compensation which has been included in NSPI’s revenue requirement.

[116] The amount included by NSPI in the test year revenue requirement for Mr.

Mann’s compensation is $607,000 being 73% of $832,000. Reducing this by 50% represents a disallowance of $303,500. In view of this disallowance, the Board will make no further adjustment on account of Mr. Mann’s compensation as a result its findings with respect to incentive compensation.

[117] The Board wishes to reiterate its earlier point that the Board of Directors of

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NSPI can pay whatever level of compensation it wishes to the employees of NSPI. This Board’s only concern is the level of compensation which is reasonable to charge to the ratepayers of the regulated Utility.

[118] When ratepayers are asked to bear the brunt of dramatically increased

compensation costs, as is the case in this proceeding, NSPI should be prepared to offer compelling

evidence that the amounts proposed are justified and it is reasonable to expect them to be recovered

from ratepayers. NSPI bears the burden of proof to demonstrate that costs are fair, reasonable and

justifiable in these and other areas. This burden has not been discharged with respect to executive

compensation.

4.5.3.2 Incentive Compensation

[119] The Board has heard no evidence which persuades it that ratepayers should

bear 100% of the cost of incentive compensation. As Mr. Huskilson stated when questioned by

Counsel for the Province as to how customers benefit from incentive compensation paid to NSPI

employees:

A. Well, I think, first of all, it's important to look at the efforts of employees as not just being for shareholders, but as being for all of the stakeholders of the company. And it's very, very hard to distinguish between stakeholders of an organization, so you can't say that the success of the organization only goes to shareholders because a lot of the success of the organization goes to customers as well. As an example, in keeping rates the same between 1996 and today, that success of the organization which, in part, was driven by incentives to employees to work hard at that activity certainly was to the benefit of customers. And so from a conceptual perspective, we have a hard time understanding how you separate the benefit that the different stakeholders get from the company, so starting with that. The way that the bonus programs, as they exist today, benefit all stakeholders of the organization are that it causes employees to have a stake in the success of the organization, so employees don't get, automatically, their total compensation. They only get the compensation when they work hard, they meet goals and they meet objectives which work well for all stakeholders. At the end of the day, if you're talking about an employee being compensated, we're going to have to compensate that employee to the level that it takes to retain that employee. And we believe that it's very important that a part of

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that compensation be at risk for that employee and that that employee have to meet significant goals in order to be able to get those incentives. And so it's an important part of our strategy to get employees pulling in the direction of all stakeholders, which includes customers and shareholders and the general public.

Q. So you do not agree that shareholders are the primary beneficiary of these incentives. A. It's absolutely impossible to separate one stakeholder in the operation of a company or an organization. If the company is successful, all stakeholders in that organization benefit from that. (Transcript, April 24/02, pp. 484-486)

[120] The Board agrees that both shareholders and ratepayers benefit from a well- run utility. The Board further agrees that it is difficult to quantify the benefit and, for that reason, reaffirms its earlier decision that an equal division of incentive compensation is the most appropriate method of allocating this cost. Accordingly, NSPI’s 2002 test year expenses are reduced by approximately $1.58 million. This amount was determined by reducing the total incentive compensation costs of $3.5 million by the amount of Mr. Mann’s incentive compensation and applying a factor of 50% to the remainder.

4.6 Operating, Maintenance and General Expenses (OM&G)

4.6.1 Submission - NSPI

[121] NSPI is projecting increases in its operating, maintenance and general expenses (OM&G) budget as follows:

Operating, Maintenance and General (OM&G) These expenditures cover labour and the various goods and services consumed in the operation of the utility. Costs for 2002 of $166 million are expected, an increase of $2.1 million or 1.3% from 2001 estimated costs. Increases in projected OM&G for 2002, relate primarily to increased labour and benefits costs. Detailed OM&G account analysis is included in Appendix 1. (Exhibit N-1, pp.16-17, original filing)

[122] NSPI did not address specific cost cutting measures in its direct evidence. The following cross-examination of Mr. Huskilson by Counsel for Annapolis is instructive:

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Q. But where you're seeking a high increase, do you not feel it's incumbent upon you to be as rigorous as possible in curtailing your costs to the minimum? A. Well, I think -- I mean, many people have asked the question as to why we are in -- why we're in the middle of the test year with this application. One of the reasons is the delay that's occurred. The other reason is that we were working very hard at the end of last year in trying to find ways of not having to come forward with an increase. But at the end of the day, the markets were such that we were unable to not have to do that. But we have traditionally worked hard to make that happen, and we continue to do that. I might just correct another point in that the 8.9 percent is not unprecedented. Certainly in the history of this regulated utility, there have been times when the price went up higher -- more than 8.9 percent.

Q. But it is your position that in putting forward this application, NSPI has curtailed all avenues -- or has explored all avenues available to it to curtail pending. A. What I would say is that as a utility and as a supplier, we work hard to control our costs and we have methods and mechanisms inside our organization that do that and that have done that successfully through the years. We continue to work in the same way.

Q. Would you agree that you've exhausted your cost containment avenues? A. As I said, at the end of last year, we were working hard to try not to come forward for this filing, but we were unable to do that. We were overtaken by the coal markets, foreign exchange situations. Q. So is that a yes, you have exhausted all your cost containment avenues? A. Yes. We have worked hard on the costs and we have our costs -- we believe that the costs we're putting forward as part of this revenue requirement are the proper costs for this test year.

Q. Mr. Huskilson, I detect you pulling your punches a little bit in the response. You're not prepared to commit to having exhausted the cost containment avenues? A. No. I would commit that we have in fact worked hard on our costs and we have our costs in as good a shape as we can get them for this period. (Transcript, April 23/02, pp.286-288)

[123] Further explanation was provided in the following exchange between Mr.

Huskilson and the Board:

Q. When Mr. Grant was asking questions the other day he asked about whether or not NSPI has explored all avenues to curtail expenditures, and I just would like to get -- I realize some of these things have already been talked about, and I apologize for that, but just going to Appendix 1, the OM&G section, and I'd just like to go to look at page 12 of 49, for example. These are just examples. And we see on there line 13 "Contracts." Contracts up by two hundred and fifty-eight -- and I'm looking at Forecast 2002 contracts is line 13 -- contracts up by two hundred and fifty-eight thousand dollars ($258,000), 131 percent. And I was just wondering how do you -- when you do these budgets, how do you ensure that expenditures are as low as they possibly can be? A. Well, the first thing we do is we benchmark ourselves against ourselves and against others, and we -- and based on those bench-marks we set targets for each one of the pieces of the business. And the way we judge whether or not someone who's managing a budget has the budget in good shape and has done a lot of work to

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ensure that they've got their costs where they should be, and they've taken every effort, we measure it against those targets that we set. And if they have a number that's better than the target that we've set, based on bench-marking and various different ways that we do that, then we say that they've done a good job and that they have done everything they could do. And if they don't meet that target, then we work on that budget and we help them to see lower costs. And so that's a very -- that's a constant process inside our company. We've been doing it very aggressively in the latter half of the '90s, and as has been seen in the documentation that's shown up. And when we compare ourselves, big picture, with other utilities, we find that it is true, we have a very good cost structure based on those kinds of costs. And so we don't apologize at all for the costs that we have in those categories because they are at the top of the heap in North America. (Transcript, May 23/02, pp.3428 - 3430)

[124] Mr. Huskilson was further questioned by the Board on the issue of reducing expenditures as follows:

Q. So you don't really know, then, whether or not number by number it's possible to achieve reductions or hold the line or lesser increases than are already showing here? A. I wouldn't say that. I would say we do know, based on our experience with this business, based on the benchmarking we've done, and based on the work we've done with people on cost conservation, we know that they have done a good job to pull these together. Is every line analysed by a senior manager in the company? No. That's not the way we run the business. But we do know that, over time, we have achieved significant efficiency gains and those gains have been achieved by this approach. And so we don't want to change that approach because that's -- we will have different results then, and they probably won't be as good as the results we've achieved. (Transcript, May 23/02, pp. 3435-3436)

4.6.2 Submissions - Intervenors

[125] Many of the intevenors and individuals who filed written comments with the

Board (and those who appeared at the evening session and at other times during the proceeding) take

issue with NSPI’s claim that it has exhausted all cost-cutting avenues in arriving at its test year

expenses. These customers argue that NSPI cannot simply pass along increased electricity costs in

the magnitude requested to its customers without clearly demonstrating that every reasonable cost- cutting measure has been exhausted.

[126] Annapolis, in its closing submission, argued:

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The proposed rates do not meet the regulatory objectives of public acceptance and stability. A substantial and important segment of the rate-paying public does not perceive the proposed rates to be fair. Especially under these circumstances, it is submitted that NSPI has an onus to demonstrate that the proposed rates are justified; that they will provide no more than a fair return on the rate base after covering only those expenses which are reasonable and prudent and properly chargeable. (Annapolis, Closing Submission, p.3)

What is clear is that while NSPI asserts that all avenues to reduce costs have been pursued, they do not do a line by line analysis of every expenditure, preferring instead to let department managers determine how budgeted money is to be spent. (Transcript, Redden, p. 296, Huskilson, p.3436). On a line-by-line basis, NSPI would only examine variances of $200,000 or more pleading it took too much effort to analyse at a greater level. (Transcript, Redden, pp.297-298) It is respectfully submitted that with the approach taken by NSPI, in the absence of a strict critical analysis of the individual line items, neither the Board nor the ratepayers can determine satisfactorily whether NSPI can reduce the total expenditures by a significant amount. (Annapolis, Closing Submission, pp. 40-41)

[127] HRM also objects to the level of expenses for NSPI, stating that:

At a point in time when power rates threaten industry, and when 51 linesmen are being laid off which has to impact outage response times, and when customers are complaining about service levels, it does not appear to be a just and reasonable expenditure in addition to providing leading executive compensation, to be paying travel expenses in the amount of $220,000 for the 6 executive team members together with training and development fees annually averaging $10-15,000 each.

A further reduction of $100,000 reducing executive travel and conference expense from $300,000 to $200,000 would appear to provide a just and reasonable level of expenditure for this item. (HRM, Written Submission, pp.23-24)

In its 1996 decision the Board held: The Board considers that the considerations which persuaded it to disallow the company’s charitable contributions from revenue requirement are equally applicable to sponsorships and grants to universities in support of scholarship programs.

NSPI has identified a total of $717,100 in Sponsorships & Donations in its revenue requirement spread across various division. With its response to undertaking U-16 NSPI has agreed that 73% of $120,000 budgeted for Sponsorships & Donations in Corporate Human Resources should be deleted.

HRM submits that it appears the label employed by the accounts, contrary to the suggestion of Chris Huskilson, correctly describes the application of the funds in this category. At a point in time when NSPI’s application for rate increases seriously threatens the jobs of Stora employees, the wisdom of “donating” money through sponsorships to the Homebuilders Industry Partnership and TIANS, for example, has to be seriously questioned as to whether it is just and reasonable. Particularly when one of the reasons given is that it provides exposure to the organization, an organization that has all the exposure it requires as a monopoly. (HRM, Written submission, pp.30-31)

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[128] ECANS, in its written submission, makes the following observation:

Page 2 of 49 of Appendix 1 provides contains[sic] other information that further paints a disappointing and unsettling picture for Nova Scotia electricity ratepayers. In particular they are:

Line item Description Amount $

011 Travel Expenses 220,000

041 Meals & Entertainment 91,000

056 Training and Development 80,000

Total 391,000

During cross examination, NSPI panel members confirmed that, except for minor amounts set aside for support staff, this money is meant for five (5) Executive Management employees. On page 2704 of the transcript, Ms. Redden describes these items as being below their $200,000 variance line and Undertaking U-69 simply confirms what was already suspected. Simply put, these individuals are accustomed to a lavish and comfortable level of self-treatment, well above what the vast majority of their customers can afford and what should be considered as reasonable for these employees to do their jobs. These line items amount to an additional $78,200 (i.e. $391,000 / 5) in annual discretionary spending for each of these individuals. ECANS does not believe these spending habits would survive a ‘used and useful’ test. If this type of thinking is pervasive at the top of the organization, it may permeate elsewhere. One final comment on this subject is prompted by statements made by Mssrs. Huskilson and Taylor (see page 2706 of the transcript) where they describe how the costs of larger management meeting are included under these line items. If that were the case, then Ms. Redden and her staff should have provided sufficient evidence to that effect. (ECANS,Closing Submission, pp.25-26)

[129] MEUNSC has recommended to the Board that the OM&G expense analysis should be expanded “... to include common ground comparisons for the entire time frame between rate applications.” MEUNSC also points out that NSPI has not had a depreciation review since the time of the last rate filing. It argues that failure to do periodic reviews on a $100 million expense “. .

. is simply another example of NSPI’s arrogant approach to regulation and its customers, and another example of mis-management.”

[130] MEUNSC further comments that:

Every assurance must be obtained that the level of expense in this category is prudent,

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necessary and does not involve discretionary spending that sends the wrong message to rate payers. Here again, an independent review rather than the trust-me approach adopted by N.S.P. may be warranted. Changes in corporate structure and lack of data make an inflationary type analysis over the time frame since the last rate application impossible. Expansion of the line-by-line analysis to include comparisons, on a common ground, since the last rate filing may be appropriate. (MEUNSC, Final Brief, p.50)

[131] SEB, in its closing argument, made the following recommendation:

The Board should undertake, in future, a continuous review of NSPI’s expenses with a view to ensuring that NSPI pays adequate attention to cost reduction opportunities. (SEB, Closing Submission, p.7)

[132] SEB further comments that: Stora Enso/Bowater did not take up the question of NSPI’s expenses in any detail, in contrast to many of the intervenors. But that is not to say that we do not believe that a close examination is essential, and indeed we support those intervenors in their efforts. The key point from Stora Enso/Bowater’s point of view, is that NSPI has not succeeded in putting forward a convincing case that it has paid adequate attention to cost reductions. In our view, the Board must itself be vigilant in the matter of expenses, and Board staff must ensure at all times that NSPI’s expenses are kept to the absolute minium. We therefore urge the Board to adopt a proactive stance with respect to expenses, not only in the current hearings, but in future months and years. (SEB, Closing Submission, p.60)

4.6.3 Findings

[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.

Document : 78377 59

[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 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. This is illustrated in the following exchange between Counsel for Annapolis and the NSPI panel:

Q. Can I go back to the question I asked a minute ago? When you prepare your budgets on a group-by-group basis, is there any examination of the costs on a line- by-line basis to determine whether or not there can be savings effected, or do you simply look at the bottom line on a group-by-group basis? A. (Huskilson) And the answer would be that we do both. So for a group that would be asking for more resources in a year, then we would be -- we would look at those resources very carefully. In the case of this particular group you're talking about, they're actually asking for less resources in this year, and so we probably would -- from a corporate perspective, we would scrutinize their costs less, but we would expect that the manager involved and that the people involved in those lines would be scrutinizing those lines. But as Zeda said, on a line-by-line basis, we would be looking to scrutinize costs at a two hundred thousand dollar level. That's the way that we've looked at it from a corporate perspective. And also, if a group is going up in costs, that's one thing. If they're going down in costs, then that's another. And so those are parts of how we would look at it. But certainly every manager in the business is responsible to manage their line by line.

Q. I'm a little confused by the answer. Are you saying that for costs of two hundred thousand dollars ($200,000) or less, you do not look to effect savings? A. (Huskilson) No. I think what we said was that we have not explained in the line-by-line variance costs that are under that threshold, and so that the level of explanation that we've done, as you said, in the notes, is at that level. Inside the business, however, each of the managers is responsible to manage their line items, and they're responsible to manage those to the best of their ability.

Q. Just to complete the line of thought, since line 26 of page 8 of Appendix 1 does not give true comparables for previous years, can you provide the true comparables as

Document : 78377 60

an undertaking? A. (Redden) We could undertake to do that. I would note that that's a relatively small amount, a hundred and eighty thousand dollars ($180,000). (Transcript, April 23/02, pp.299-300)

[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.

[138] With respect to NSPI’s inclusion of sponsorships and donations in its test year expenses, the Board sees no reason to vary from its ruling in 1996 where the Board stated that:

. . . In its 1996 budget the Company proposes to spend a total of $158,000 on “sponsorships” under its Public Affairs budget and $69,000 in support of scholarship programs at Nova Scotia universities. The Company states that its sponsorships in the Public Affairs area “support the corporate involvement at the community level, and are designed to build a favorable corporate image”. Sponsorships in 1995 included various Chambers of Commerce, the G-7 Conference, the Camp Hill Ski Challenge and the Art Gallery of Nova Scotia. The Board considers these sponsorships and the general scholarship program to be analogous to the corporate donation issue which the Board addressed in its decision on the Company’s 1993 rate application. The Board said in that decision: “In the case of a monopoly utility the customer cannot go to another company if dissatisfied with the utility’s spending decisions. Many regulators consider that there is no relationship between a utility’s discretionary spending on donations and the level and quality of customer service. The spending on donations in effect becomes an involuntary tax on the customers”.

The Board considers that the considerations which persuaded it to disallow the Company’s charitable contributions from revenue requirement are equally applicable to sponsorships and grants to universities in support of scholarship programs. While these programs may enhance the Company’s corporate image, they do not directly benefit customers and the

Document : 78377 61

customers have no say in the choice of sponsorships. The Board will accordingly reduce the Company’s revenue requirement by $227,000. (NSPI Decision, P-868, pp.23-24)

[139] Accordingly, NSPI’s test year expenses relating to sponsorships and donations are disallowed. Exhibit N-21 lists the various items included in the "Sponsorships and other

Donations" category. The impact on the revenue requirement is $717,100 less the related amount billed to affiliate entities. This reduces test year expenses by a further $635,800.

[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.

[142] The Board also directs NSPI to provide, on an annual basis, a detailed analysis showing executive management expenses, including compensation, expenses, memberships and other personal benefits including loans. Only then can the Board be satisfied that expenses are

“...reasonable and prudent and properly chargeable...” in accordance with Section 45(2) of the Act.

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4.7 Depreciation Expense

4.7.1 Findings

[143] NSPI forecasts depreciation expense of $102.8 million for the 2002 test year,

an operating expense category exceeded in size only by fuel and purchased power and operating,

maintenance and general. NSPI last filed a depreciation study with the Board for approval in August,

1995. It was based on data as at December 31, 1994. In response to UARB IR-213, NSPI advised

that it normally undertakes depreciation studies as part of a general rate application. However,

“...due to the lead time required to complete the study, NSPI has not proposed any changes to its

depreciation rates as part of this application”. At the hearing, Ms. Redden advised that NSPI had

contacted a number of depreciation consultants and that they all indicated that a study would take

more than the two months available. The Board considers that NSPI’s depreciation rates should be

reviewed more frequently than once every seven years. NSPI is directed to retain an external

depreciation consultant and to file the consultant’s report with the Board for review not later than six

months from the date of this decision. The Board recognizes that NSPI predicts that its depreciation

expense is likely to increase as a result of the review and that NSPI’s current composite depreciation

rate (2.72%) is lower than the equivalent rate for most Canadian electric utilities (Undertaking U-71).

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5.0 CAPITAL STRUCTURE AND RATE OF RETURN

5.1 Capital Structure

5.1.1 Submission - NSPI

[144] NSPI seeks to increase the common equity component of its capital structure

from 35% to 40% for the test year with the ability to increase this portion to 45% over time. In its

direct evidence NSPI states that:

... a higher equity ratio is required to ensure that the capital markets continue to exhibit the confidence that they have demonstrated over the last several years. (Exhibit N-1, p.28)

[145] NSPI’s expert witness, Richard Falconer of CIBC World Markets,

testified that:

The current capital structure, which allows for 33% to 35% common equity... is inappropriate given the higher risks the Company is now facing. An increase in the common equity component to a range of 40 to 45% and a subsequent decrease in the debt and preferred share components would result in a capital structure more in line with NSPI’s “A” rated peer group. (Exhibit N-1, Falconer, Direct Evidence, p.15)

[146] NSPI’s expert witness, Kathleen McShane of Foster and Associates, a U.S.

based consulting firm, stated in her direct evidence that:

NSPI’s proposal to increase its common equity ratio to 40% is consistent with its business risks and the objective of maintaining debt ratings in the A category. With a common equity ratio of 40-45% in the test year, NSPI would be considered by the equity markets to be of average investment risk relative to its Canadian peers. (Exhibit N-1,McShane, Direct Evidence, p.2)

[147] In December, 2001, subsequent to the filing of direct evidence by NSPI, Mr.

Falconer and Ms. McShane, Standard & Poor’s lowered NSPI’s long-term corporate credit rating and

senior unsecured debt rating to "BBB+” from "A -". NSPI submits that the current capital structure is inadequate to achieve an "A" credit rating and that a "BBB" rating is "neither optimal nor in the long term desirable". It further submits, inter alia, that "BBB" rated companies may not be able to raise debt with terms longer than 10 years and that the downgrade is likely to adversely affect both

Document : 78377 64 the "...availability of bank financing and its costs".

[148] The impact on revenue of the proposed changes to capital structure was

outlined in NSPI’s responses to Annapolis IR-23.1, MEUNSC IR-25 and Undertaking U-12. These

responses can be summarized as follows:

· Increasing the equity component from 35% to 40% results in an increase in the required revenue of $3.3 million. · Increasing the equity component from 35% to 45% results in an increase in the required revenue of $11.6 million.

[149] The Board questioned Ms. McShane as to whether arriving at the appropriate capital structure involves a qualitative assessment as opposed to a quantitative one:

A. I don't disagree with the comment that there is no formula for determining the appropriate capital structure and it is in some measure a qualitative assessment. I think that we are helped with the information that we do have provided by other companies who have capital structures tested by the market in the sense that you can look at different companies with different capital structures and other financial parameters and see what bond ratings have been granted to those companies, so you have a good sense of at what cost they can raise debt. (Transcript, May 14/02 p.2175)

[150] Counsel for NSPI introduced a number of decisions which showed that certain

Canadian jurisdictions allowed higher equity ratios than those recommended by Drs. Roberts and

Kryzanowski, the Province’s expert witnesses. Exhibit N-62, a decision of the Newfoundland Board

of Commissioners of Public Utilities, allowed an equity component for rate making purposes of

45%. In addition, the legislated minimum ratio for Maritime Electric is 40%. Drs. Roberts and

Kryzanowski also confirmed that Exhibits N-65 and N-66 show business profiles, as measured by

Standard and Poor’s, for Consumers Gas and TransCanada Pipeline of 2 (out of 10 with 10 being the

most risky) as compared to 4 for NSPI, as shown in Exhibit N-47. NSPI’s Counsel also pointed out that TransCanada Pipeline recently applied to the National Energy Board to increase its common equity component to 40% from 30%. Drs. Roberts and Kryzanowski were asked whether by raising

Document : 78377 65 the equity component to 40% NSPI could expect to see a reduction in the cost of debt:

62. Q. Would you agree that if NSPI's capital structure is changed to allow a 40-percent common equity that there will be a reduction in the cost of debt because of lower financial risk? A. (Kryzanowski) Yes, that's right. A. (Roberts) Yes, I would agree.

63. Q. Okay. And would you agree, all things being equal, that a return on common equity on a 40-percent capital structure would be slightly lower than at 35 percent? A. (Roberts) A return on common equity at a 40-percent capital structure would be slightly lower, yes, I would agree. (Transcript, May 15/02, pp.2268-2269)

5.1.2 Submissions - Intervenors

[151] In their direct evidence, Drs. Roberts and Kryzanowski suggest that NSPI is not facing any more risk than in 1996, when the Board approved a maximum common equity ratio of

35%. They conclude that:

Accordingly, that ratio will continue to serve NSPI well in the test period. (Exhibit N-58,p.48)

Drs. Roberts and Kryzanowski further testified that an equity component of 35% is reasonable compared to the actual and allowed ratios for other integrated electric utilities and is reasonable in the light of past decisions of the Board. They further compared this level with a number of gas utilities. In Schedule 5 of their direct evidence (Exhibit N-58), the average common equity ratio for five gas utilities was calculated as 36.44%. In total, six estimates of equity ratios were considered by Drs. Roberts and Kryzanowski with an overall range of 33% to 37%, leading to their final recommendation of the continued appropriateness of 35%.

[152] During questioning by the Board, James Rothschild, a U.S. based financial expert retained as a consultant to Board Counsel stated that, in his opinion, a 40% common equity

Document : 78377 66 ratio is desirable, but only if the parent company, Emera, has a similar ratio. Emera’s capital equity ratio as at December 31, 2001 was 35.6%. It is Mr. Rothschild’s view that if NSPI increases its common equity ratio, with no corresponding increase in the common equity ratio of Emera, there will be no improvement in NSPI’s bond rating. This opinion is set out in his direct evidence as follows:

... The higher common equity ratio of NSPI should only be used for ratemaking purposes if the consolidated capital structure of Emera is increased to at least 40% as well. Until both these changes occur, the proper capital structure to use for regulatory purposes is the actual capital structure of NSPI as I have proposed. The extra cost associated with the higher common equity ratio is only justifiable if that cost increase is offset by declines in both the cost of equity and the cost of debt. The cost of debt only declines for NSPI if the common equity ratio is actually increased to 40% by both NSPI and Emera. (Exhibit N-73, pp. 7-8)

[153] Mr. Rothschild indicated that with a lower debt rating, the next time that NSPI goes to the market it will incur a somewhat higher interest cost. However, he indicated that:

... they're still investment grade, and I don't think there needs to be any undue concern about the bond rating. (Transcript, May 16/02, p. 2568)

[154] When questioned by MEUNSC, Mr. Rothschild commented on the relative importance of a deemed capital structure versus an actual capital structure from the viewpoint of credit raters:

Q. Good morning, Mr. Rothschild. I, too, have only one question, and my question is -- and it seems to be implied by what you've said this morning that if NSPI and, in your argument, Emera, were to move to 40 percent equity rating by retaining earnings, and were still receiving a regulated rate of return on the basis of a 35 percent weighting, it's your belief that the bond markets would recognize the increased portion of equity over time with a lower or better bond rating? A. The actual capital structure of NSPI and Emera has a far greater influence on the bond rating than what the Board allows. Said another way, if the Board were to set rates based upon a 40 percent common equity ratio, and Emera and NSPI maintained 35 percent, it would do very little to help the bond rating.

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Q. So the bond raters are looking at the real number, the actual — A. They're looking -- yes, they're looking at not only what the real number is now, but what they expect the real number to be. And that's not just capital structure. It's covered ratios and so on. And I don't mean -- I don't want to mislead you in that, that other things being equal the larger the profits the company earns, the higher the coverage ratios will be. But, the impact on the coverage ratio from a somewhat higher allowed return on equity is far less than the impact on the coverage ratio of an increase in the equity ratio. (Transcript, May 16/02, pp.2514-2515)

5.1.3 Findings - Capital Structure

[155] After considering all the evidence and submissions respecting an appropriate capital structure for NSPI, the Board finds that there is insufficient justification to increase the common equity component from its present level of 35% to 40% at this time. The Board understands the benefits which could flow from an increase in the common equity ratio. However, the Board also accepts Mr. Rothschild’s view that without a corresponding increase in the common equity ratio of NSPI’s parent company, Emera, there will likely be no overall benefit accruing from an increase in the common equity level of NSPI. As noted above, Emera’s common equity ratio at

December 31, 2001, was 35.6%.

[156] The Board has seen no evidence to indicate that Emera is prepared to make a similar increase in its common equity ratio. Accordingly, the Board directs that the common equity level of NSPI remain at 35% for rate-making purposes. This will reduce the revenue requirement by

$3.3 million. The Board would indicate that it has no objection to NSPI increasing its actual equity ratio in the future to 40%. However, at any future rate hearing, the Board will determine what equity ratio is appropriate for rate-making purposes. At that time, among other things, the Board would consider the level of equity in Emera.

5.2 Rate of Return on Equity

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5.2.1 Submission - NSPI

[157] Based on the recommendation of its expert witness, Ms. McShane, NSPI

requests that the Board approve a return on common equity of 11.0% for the purpose of setting rates, with the ability to earn up to 12.0%. This represents an increase from the current allowed return range of 10.50% - 11.00% approved by the Board in its 1996 rate decision and an increase in the earnings band to 100 basis points. Rates were set in 1996 on the basis of a return on common equity

of 10.75%.

[158] In her direct evidence, Ms. McShane said that:

a 100 basis point range better recognizes the potential volatility of returns from year-to-year and creates a more symmetric potential to earn above and below the allowed return. (Exhibit N-1, McShane, Direct Evidence, p. 77)

[159] She submitted that:

NSPI should have the same opportunities as other utilities to earn returns above the allowed return. Most utilities in Canada subject to traditional rate of return regulation are not required to refund earnings above the allowed return. (Exhibit N-1, McShane, Direct Evidence, p.78)

[160] The impact on revenue of the proposed changes to the allowed rate of return

on equity was set out in NSPI’s response to MEUNSC IR-25 and Undertaking U-12, and can be summarized as follows:

· Increasing the rate of return on equity from 10.75% to 11.0% results in an increase in the required revenue of $2.0 million.

· Increasing the rate of return on equity from 11.0% to 12.0% results in an increase in the required revenue of $14.0 million.

[161] Ms. McShane used three tests to arrive at her recommended range: the equity

risk premium method, the discounted cash flow method (DCF) and the comparable earnings method.

In applying the risk premium method, she estimated the risk-free rate at 6% for the 2002 test year.

Using three separate risk premium approaches, she concluded that the risk premium analysis

Document : 78377 69 indicated a risk premium of 4.25%, for a cost of equity of 10.25% before any adjustment for financing flexibility. Using the constant growth model, she applied the DCF test to a sample of U.S. electric utilities and derived a cost of equity of 11.1% to 11.3%. She added a 50 basis point financing flexibility adjustment to provide compensation for flotation costs. She applied the comparable earnings test to samples of Canadian and U.S. low risk industrials and concluded that the fair return based on the comparable earnings tests is in the range of 12.0% to 13.0%. After considering the results of these three approaches, Ms. McShane recommended a rate of return on equity of 11% to 12%.

[162] In its post-hearing brief, NSPI addressed the following points concerning the testimony of Drs. Roberts and Kryzanowski:

The CAPM results are subject to considerable variation, depending on the periods chosen for estimation of the risk premium. It is submitted that Drs. Kryzanowski and Roberts were selective with respect in their choice of time period to measure historic risk premiums. For purposes of their evidence they concentrated on the 1957 to 2001 data because data prior to 1957 is not available for the TSE index. (NSPI, Post-Hearing Brief, p. 33)

They do acknowledge that data for the Canadian equity market is available prior to 1957 and at page 69 of their testimony calculate an equity risk premium of 5.5% for the period 1948 to 2001. However, they lower the risk premium they calculate by excluding the first 3 or 4 years after the war, claiming that period was unusual. NSPI believes the recommendation of these witnesses is unreasonable on its face and should be disregarded. A return of just over 8% is equal to a risk premium of less than 1% over NSPI’s cost of debt. (NSPI, Post-Hearing Brief, p. 34)

NSPI would also reiterate the point made earlier that the Province’s witnesses did no kind of evaluation to see if their recommendations were compatible with maintaining the company’s financial integrity. Their recommendations would allow NSPI to achieve interest coverage consistent with debt ratings in the junk bond category. In NSPI’s submission, acceptance of these witnesses’ recommendations would be financially disastrous to the Company, its bondholders and equity shareholders. (NSPI, Post-Hearing Brief, pp. 35-36)

5.2.2 Submissions - Intervenors

[163] In their opening statement, Drs. Roberts and Kryzanowski recommended a

Document : 78377 70 rate of return on common equity of 8.20% as opposed to the 8.02% they originally recommended in their pre-filed evidence. Their recommendation is based upon their application of the equity risk

premium test. Drs. Roberts and Kryzanowski did not use the DCF method used by Mr. Rothschild

and Ms. McShane, or the comparable earnings test used by Ms. McShane.

[164] In his cross-examination of Drs. Roberts and Kryzanowski, Board Counsel

asked why they did not use the DCF method. They stated that, in their view, the DCF method has

two problems, that of circularity and obtaining an accurate growth forecast.

[165] In his opening statement, Mr. Rothschild summarized his recommendation

that, assuming a 35% equity ratio, an appropriate rate of return on equity would be 10.15%. He

further stated that if NSPI’s equity ratio were to increase to 40%, his recommended rate of return

would drop to 9.95%. A further increase in the equity component would result in a further lowering

of the rate of return on equity. His recommended level of 10.15% was based on a recommended

equity cost of 9.75% and a capital structure risk adjustment of 0.40%.

[166] Mr. Rothschild did not use the comparable earnings approach and he stated

that this approach is not valid since it does not address the cost of equity. Instead, it simply

considers the returns on book equity that were achieved without testing whether these returns were

higher or lower than necessary.

[167] In his direct evidence Mr. Rothschild also addresses the methodology used by

Ms. McShane in her DCF analysis:

Document : 78377 71

Summarizing, the major problem with Ms. McShane’s Discounted Cash Flow (DCF) cost of equity computation is that she applies the DCF Method as if investors not only expect short- term analyst forecasts to be accurate in the short-term, but also somehow applicable in the long-term. Ms. McShane’s analysis implies that investors believe the average return on book equity (ROE) for her selected group of comparative electric companies will keep increasing forever. Ignoring her inappropriate stretching of short-term forecasts to the horizon, her DCF method is mathematically invalid because it is not indicative of the expected growth in dividends, stock price, or book value even over the next five years. This large mathematical error is repeated in the portion of Ms. McShane’s risk premium based methods that rely upon her DCF method. (Exhibit N-73, p.8)

[168] Under cross-examination, Mr. Rothschild indicated that the DCF method is the most common method used in the United States for calculating return on common equity:

Q. Would you agree -- even if others don't, but would you agree that the discounted cash flow method is a method favoured in the United States in calculating return on common equity? A. That is very easy. Yes. (Transcript, May 15/02, p.2414)

[169] In responding to a question from the Board, Mr. Rothschild further discussed the difference between his approach and that of Drs. Roberts and Kryzanowski:

Q. Okay. I think based on the evidence that we have an understanding why -- or first of all, I guess I should say you're in the middle. Your recommendations are in the middle between the Province's experts and Ms. McShane for the company. And I think we have an idea why your recommendations are lower than Ms. McShane's. I wonder if you could just summarize why your recommendations are higher than the experts for the Province. A. Yes, I can do that. I give primary weight to the DCF method. And that's not because I haven't given significant weight to risk premiums in the past. My concern is that right now, a risk premium method is understating the cost -- or let me say a properly applied risk premium method. I've seen people even today who find ways to have the risk premium approach come up with too high results by doing things like using the arithmetic average. But a properly applied risk premium will understate the cost of equity because of the flight to quality that is prevalent today with the combined fears of heightened world tensions both relating to the terrorism and the ongoing problems in the Middle East, and always uncertainty when there's a recession. Things are starting to look better in terms of hopeful -- a recovery from recession, but those things tend to create a flight to quality, and when that happens, you can get a temporary distortion in risk premiums. When you implement a risk premium method the way most people do it, and I believe the way all of the witnesses in this case have done it, you're looking to historic relationships so that you can add a risk premium to today's cost of debt, which is great and very helpful, but only work so long as today is reasonably representative of what was the historic situation. And I think it's just hopefully temporarily out of balance. (Transcript, May 16/02, p.2553)

Document : 78377 72

5.2.3 Findings - Rate of Return on Equity

[170] The Board has considered the evidence of Ms. McShane, Drs. Roberts and

Kryzanowski and Mr. Rothschild. The Board believes that the rate of return on equity should be set

at a rate which fairly reflects the risk associated with an investment in NSPI. In the Board’s view,

the rate of return of 10.15%, as recommended by Mr. Rothschild, most fairly meets that test.

[171] The Board believes that the rate of return advocated by Drs. Roberts and

Kryzanowski is too low given the financial and business risks faced by NSPI and the current

economic environment. On the other hand, the level of return suggested by Ms. McShane is more

generous than warranted given the present economic environment.

[172] Accordingly, the Board sets the rate of return on equity at 10.15% for purposes

of setting rates. The Board continues to consider that it is useful to establish an earnings range,

which the Board sets at 9.90% to 10.40%. Setting the rate of return on equity at 10.15%, has the

effect of reducing NSPI’s revenue requirement by $8,500,000.

5.3 Return on Rate Base

5.3.1 Findings

Document : 78377 73

[173] In Exhibit N-1, NSPI included Table 3.5 which sets out the calculation of its rate base and rate of return on rate base. It shows a projected rate of return on average rate base of

10.25% for the 2002 test year. The rate of return on rate base is derived from the financial forecast and for the test year assumes a rate of return on equity of 11.0% and a 40% equity component. NSPI

has not asked for approval of a specific rate of return on rate base. The supporting details of the

calculation of rate of return on rate base as presented in NSPI’s Table 3.5 are reproduced below.

Table 3.5 Nova Scotia Power Inc. - Rate of Return on Average Rate Base Years Ended December 31st Millions of Dollars

Proposed Rates Test Proposed Rates Actual Forecast Present Rates Year Forecast (May 1st) Forecast 2000 2001 Forecast 2002 2002 2002

Net Plant in Service $2,312.9 $2,332.2 $2,333.0 $2,333.0 $2,333.0 Less: Non Utility Plant 5.5 5.2 4.9 4.9 4.9

NET UTILITY PLANT IN SERVICE $2,307.5 $2,327.1 $2,328.1 $2,328.1 $2,328.1

Add: Allowance for Materials & Supplies 85.3 96.7 95.8 95.8 95.8 Allowance for Working capital 18.0 19.3 24.1 24.1 24.1

Total Additions 103.3 116 119.9 119.9 119.9

Rate Base 2410.7 2443.1 2448 2448 2448

Average Rate Base 2392 2426.9 2445.6 2445.6 2445.6

Excess of Operating Revenue Over Operating Expense 245 249.3 187.3 250.7 233.6

Rate of Return on Average Rate Base 10.24% 10.27% 7.66% 10.25% 9.55%

U-2 provides discussion by NSPI on ROR and difference between rate base and total capital. U-5 shows difference between rate base & capital in table format. (Exhibit N-1, Table 3.5)

[174] In its post-hearing brief, NSPI points out that it has presented its financial

tables consistent with its presentation in its 1993 and 1996 rate applications. This Board, in prior

NSPI rate decisions, has based the revenue requirement for the test year on an allowed return on

equity. The Board’s focus has been a return on equity, and not return on rate base. Once the rate of

return on common equity is determined, it is possible to calculate the return on average rate base.

Document : 78377 74

[175] The Board directs that NSPI, as part of the required Compliance Filing set out in Section 7 of this decision, recalculate the return on average rate base taking into account the adjustments made to test year revenues and expenses as a result of this decision. Following a review by the Board, including any modifications which may be necessary, the Board will issue a final Order which, among other things, will approve the rate of return on average rate base.

Document : 78377 75

6.0 AFFILIATE ACTIVITY

6.1 Code of Conduct - PricewaterhouseCoopers Report

6.1.1 Submissions

[176] In its direct evidence, NSPI states that:

On December 2, 1998, NSPI shareholders approved a proposal to reorganize NSPI to create a holding Company structure. One month later, on January 1, 1999, all NSPI common shareholders exchanged their shares for NS Power Holdings Inc. (“NSPHI”) common shares on a one-for-one basis. In June 2000, NSPHI was renamed Emera Inc. (“Emera”). NSPI continues as a wholly-owned subsidiary of Emera. As a consequence of this new structure, the Board approved the NSPI Code of Conduct on an interim basis on March 16, 2001, effective September 16, 2001. The Board ordered that the Interim Code is to remain in force until a final Code of Conduct is approved by the Board in a future general rate hearing. The Code, provided at Appendix 5, provides an effective framework to govern utility/affiliate activity. Key elements of the Code include the following: ... Statement of Principles - 1) NSPI will neither subsidize, nor be subsidized by an affiliate’s current or prospective activities and 2) Competition in markets where NSPI’s affiliates are active will not be impaired by non-market behaviour by NSPI. . . . NSPI believes the Code as approved by the Board provides an effective balance between appropriate regulatory oversight and pursuit of affiliate efficiencies and growth opportunities. The reporting mechanisms in place will provide the Board with a thorough insight to NSPI activity. We are not, at this time, seeking any modifications to the Code. As part of this general rate application, we request the Board finalize its approval of the NSPI Code of Conduct. (Exhibit N-1, pp.64-65)

[177] The development of a Code of Conduct was initiated between the Board and

NSPI in light of the increasing number of NSPI affiliates and the potential impact of their activities

on NSPI ratepayers. As noted above, the Interim Code, attached hereto as Appendix C, became

effective on September 16, 2001. In preparation for the rate hearing, the Board engaged

PricewaterhouseCoopers (PWC) to review NSPI’s compliance with the Interim Code and, as well, to

recommend any changes which should be made to the Code before receiving final approval by the

Board. The PWC report drew the following conclusions:

1. The Code is generally effective in its primary purpose of ensuring that the customers of NSPI are not harmed by transactions between NSPI and its affiliates. 2. There are two areas that we believe require refinement to be compliant with the

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Code. These are: - Establishment of a fair method for allocating corporate support services costs; and - Establishment of fair market values for transactions with affiliates. 3. Management at NSPI is making significant efforts to comply with the spirit of the Code although we note there are other minor areas in which compliance is not absolute. (Exhibit N-19, p.2)

[178] PWC expanded upon its conclusions as follows:

Significant Findings and Recommendations

As noted, our major findings are around the allocation of corporate support services costs and the fair market value of transactions with affiliates. These findings and recommendations are: 1. We believe that the current method used by NSPI to allocate corporate shared services costs does not appropriately measure the amount of specific services being provided to or being used by its affiliates. We recommend that NSPI review alternative methods of allocating its corporate shared services costs that directly relate to the amount of the service utilized or the effort expended. We expect that different allocation methods will be used for different types of costs. We do not know if NSPI is in compliance with Section 6.11 of the Code as we do not know the amount of the adjustment to the costs allocated to the affiliates that would be required if these alternative measures were used. 2. We believe that NSPI is in compliance with Section 6.8 of the Code with respect to the sale of steam to Strait Energy as fully allocated cost is appropriate in the circumstances. However, we believe that in keeping with the spirit of the Code, an attempt to determine the fair market value of these transactions should have been made. 3. We do not have enough information to determine if NSPI is in compliance with Section 6.8 of the Code in respect of its sale of energy to Emera Energy Inc. At issue is the splitting of total margin on the resale of this energy of [redacted]. It is currently split [redacted]. NSPI management has indicated that the agreement to allocate the margin is temporary and that work on developing a pricing methodology is ongoing.

4. We recommend that, where the fair market value for affiliate transactions is not readily determinable, NSPI introduce the transfer pricing methodologies recommended by the Organization for Economic Co-operation and Development (OECD) to determine fair market value for transactions with affiliates. This is of particular concern in instances, such as those described in 2 and 3 above, where NSPI produces the product that is delivered to the ultimate customer but where an affiliate is between the customer and NSPI. Allocation of the earned margin between NSPI and the affiliate should be based on established transfer pricing methodologies. [Exhibit N-19, p.5 (Deletions in original text)]

[179] During the hearing, NSPI vigorously disputed PWC’s findings concerning its allocation process for purposes of sharing expenses with Emera.

[180] The following exchange with Board Counsel is illustrative:

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And there's a more elaborate discussion of that same point on pages 6 and 7. And I'm not going to review that evidence, but my question to the panel is whether or not it is NSPI's intention, in light of the PWC report, to change its method of allocating shared corporate services costs. (Huskilson) At this point the answer would be no. (Transcript, May 22/02, p.3113)

(181) NSPI, in its post-hearing brief, states that:

While NSPI submits the Code is worthy of approval, if the Board is more comfortable continuing interim approval pending further decision on affiliate transactions, NSPI would accept that. (NSPI, Post-Hearing Brief, p. 56)

[181] During the hearing, NSPI advised that it was preparing a response to the PWC report. NSPI filed its response as an attachment to its post-hearing brief. While NSPI stated its fundamental agreement with the report, the following passages from its response are noteworthy:

In addition to the above, the Consultants’ report includes a number of finding[s] concerning 2002 transactions and process related recommendations upon which NSPI wishes to comment. It is important to note that in discussing Code of Conduct processes within this submission, NSPI has not changed its position that these are internal procedures directed toward the achievement of Code compliance. As such they do not require or warrant UARB approval. As affiliate relationships change over time, the Guidelines will be revised accordingly. Consistent with this, where the recommendations of the Consultants concerning Code processes are considered to contribute positively to Code of Conduct compliance, these will be incorporated within the internal Guidelines. The Board’s expectations concerning affiliate activity are clearly expressed within the terms of the Code of Conduct. The scope of the Regulator’s oversight of this activity as outlined in the Code’s provisions is broad and adequate to determine Code compliance. It must be left to the Utility to develop the appropriate internal procedures to ensure the provisions of the Code are met. NSPI management understands that should we fail to develop the necessary internal processes to maintain compliance, the Regulator will respond. Beyond these items, the Consultants also recommended a schedule of unadjusted differences be appended to the Audit Report and management and post audit correspondence involving the Code be filed with the UARB. NSPI believes these latter recommendations to be inappropriate; in the case of the former, because it will tend to focus compliance processes on relatedly immaterial areas and in the case of the latter because expanding the audience of such correspondence beyond internal management may negatively impact the value of the information in improving internal processes. (NSPI, Post-Hearing Brief, Appendix B, pp.1-2)

[182] Intervenors, including HRM, MEUNSC, the Province and SEB, expressed concern at the extent of NSPI affiliate activity and the potential for harm to NSPI and ratepayers under the existing Interim Code. They urge the Board not to give final approval to the Code at this

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[183] Annapolis, in its rebuttal submission, argued that:

In each of these transactions, there is a host of ways in which NSPI may be disadvantaged. In many circumstances, the valuation placed upon services is subjective at best and involves the application of a fair measure of judgement on the part of the individual assigning the value. In view of the unlimited number of transactions in which NSPI may be involved with its affiliates, the subjective nature of the valuations, and the effective inability or impracticality of ratepayers challenging affiliated party transactions, we would submit that the Board refuse to approve a Code of Conduct founded upon the principle that affiliated party transactions shall cause no harm to the ratepayers. In our submission, the Board should direct NSPI to prepare and submit to the Board a new Code of Conduct in which the principle is established that NSPI shall not enter into an affiliated party transaction unless it is able to demonstrate positively that the transaction will be of benefit to NSPI and its ratepayers. (Annapolis, Rebuttal Submission, p.13)

6.1.2 Findings

[184] The Board notes that, according to Exhibit N-99, there are 42 companies

under the Emera corporate umbrella. These companies are affiliated with NSPI and, in some cases, are involved in “shared services” with NSPI, (which will be discussed further in Section 6.3 of this decision). According to the evidence, executives and other staff perform functions for NSPI and affiliated companies.

[185] The Board is cognizant of the potential risk to ratepayers of unregulated

affiliate activities. The Interim Code was developed in order to institute a number of formalized

measures to protect NSPI ratepayers. The Board finds that the PWC report is helpful in that it

focusses attention on potential weak points in the existing Code. Likewise, the Board finds the

suggestion of Counsel for Annapolis, that the test for affiliate activity should be raised from “no

harm” to “demonstrate a benefit” to NSPI ratepayers, to have merit.

[186] NSPI witnesses acknowledged, when questioned by Counsel for Annapolis,

that transactions with affiliates are entered into on the basis that NSPI should realize a benefit, as

Document : 78377 79 indicated in the following passage:

Q. Do you think that any transaction between NSPI and Emera or an Emera affiliate should contain a benefit to NSPI? A. (Whalen) That's the general principle of the code, that there be a mutual sharing of any benefits and there are guidelines in the code in terms of assessing that. (Transcript, April 23/02, pp. 337-338)

[187] The Board finds that it is not appropriate, at this time, to give final approval to

the Interim Code of Conduct. There appears to be merit to the suggestion that Article 1.1 of the

Code be amended to require that affiliate transactions must demonstrate a benefit to NSPI ratepayers

as opposed to causing them no harm. The Board intends to retain independent consultants to review

the implications of such a change, and also to review the desirability of making further changes in

light of the recommendations contained in the PWC report, the evidence presented at the hearing,

and the findings of the Board in this decision.

[188] The Board generally accepts the recommendations of the PWC report.

Additional Board comment on specific recommendations by PWC are set out later in this decision.

The Board agrees with PWC’s recommendation that NSPI’s external auditors should provide to the

Board a schedule of their unadjusted differences (i.e., a summary of immaterial errors or exceptions),

along with the annual audit report on compliance with the Code. In addition, the Board directs that

copies of management or post-audit letters issued by NSPI’s external auditors in connection with

their audit of NSPI’s compliance with the provisions of the Interim Code of Conduct be filed with

the Board by the external auditors. While the Board agrees with NSPI’s contention that individual

transactions may involve relatively small amounts, it believes that this issue goes beyond NSPI’s

materiality threshold. Disclosure of this information supports the fundamental principles of fairness

and accountability with respect to affiliate activities. The Board has no desire or intention to micro-

manage NSPI. However, at the present time, Emera appears to be in the process of transferring to

Document : 78377 80 various Emera affiliates a number of activities carried out by NSPI and the Board has concerns about the fairness and efficacy of these transactions. Accordingly, the Board believes this reporting tool is

a helpful instrument in protecting the interests of NSPI ratepayers.

6.2 Emera Energy - Agency Agreement

6.2.1 Submission - NSPI

[189] During the course of the hearing, NSPI indicated that it intended to enter into

an Agency Agreement with its affiliate, Emera Energy, covering fuel procurement, export electricity

sales and gas sales. The transfer of these functions apparently took place in late 2001. In its

evidence, NSPI has identified $672,000 as the amount of fees to be paid by NSPI to Emera Energy

for the provision of fuel procurement services by Emera Energy during the test year.

[190] Mr. Huskilson advised that NSPI has engaged Dr. Jay Lukens, a Texas-based

consultant, to provide advice with respect to the Agency Agreement including its terms and

regulatory precedent for its implementation.

[191] Under cross-examination by Counsel for Annapolis, Mr. Huskilson described

how the agency agreement would work with respect to export energy sales:

Q. If more than 300GW of hours are generated, does NSPI participate in the excess sales? A. So I can't talk to you about the detail of that right now because it's not finalized, but, in principle, NSPI will participate in any volume that gets sold. So if we sell at traditional levels, so at what we call the five-year average, then NSPI will take in about a million and a half dollars, which is what is in the current revenue requirement. If we're able to exceed that, then the possibility exists that NSPI will earn more than traditional levels. But, I might add that the one point five million dollars ($1.5 million) is about three hundred thousand, three to four hundred thousand dollars above what our traditional level of margin is on these sales. (Transcript, April 24/02, p.415)

[192] Under cross-examination by Counsel for Annapolis, the NSPI panel described

the status of the Agency Agreement at the time of the hearing as follows:

Q. I want to turn to another topic. I understand that NSPI engages employees of

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Emera to assist and advise in fuel purchasing. A. (Taylor) The agency arrangement that we have with Emera Energy Services does include advice on fuel purchasing.

Q. Okay. How long has that arrangement, agency arrangement, been in place? A. (Taylor) The agency arrangement went into place in the fall of 2001.

Q. Is there an agreement documenting the terms of that agency agreement? A. (Taylor) There is a -- there is an agency agreement, there is.

Q. Okay. Has that been filed with the Board? A. (Taylor) Pardon me, Mr. Grant?

Q. Has that been filed with the Board? A. (Taylor) Also it is a tentative draft agreement that is also part of the package that is being reviewed internally subject to the consultant advice and is being built, so it's not finalized yet.

Q. Okay. Is Emera Fuels --- A. (Huskilson) The entire relationship, whether that be fuel procurement, export energy, commodity trading, that whole relationship is all part of the agency relationship. We've created -- as I said before, the process is we've created a model, which is the one that Mr. Taylor was referring to. We've taken that through an expert review. The expert review has made recommendations for some changes, so we're making those changes. We now have this report, which is also recommending some changes, so we're making those changes. And then that, the output of all of those changes and the expert review, will be the final document. But it's all one factor, whether it's fuel procurement, whether it's export sales, whether it's -- or whether it's energy trading and financials that's all one relationship. (Transcript, April 24/02, pp.417-419)

[193] Mr. Taylor described Emera Energy’s activity in coal markets:

Q. How long has Emera been active in the coal market? A. Emera Energy and Nova Scotia Power entered into a tentative agency agreement in September of 2001. I believe that also -- though not certain because I don't know the total dealings of Emera Energy -- that that would be when they started their coal procurement activity. (Transcript, April 29/02, p.1082)

[194] While Mr. Huskilson and Mr. Taylor expressed the view that NSPI and the ratepayers would derive a benefit through savings and expertise from using Emera Energy as an agent for fuel procurement and to sell excess power, they also indicated a limited knowledge of

Emera Energy’s operations.

[195] The following exchanges between Counsel for Annapolis and Mr. Huskilson are informative:

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Q. Well, let's come to that. On several occasions during the hearing, you've indicated that you're not fully aware of what's going on inside Emera Energy. Correct? A. Yes, that's correct.

Q. And Emera Energy at the present time, although not under formal contract -- the contract is being developed -- the agency agreement is being developed -- is NSPI's fuel procurement agent. A. Well again, we have to get into legal entities now. Emera Energy is the umbrella company that holds all of those assets. It holds Emera Fuels, it holds Sable Offshore, it holds Maritimes and Northeast. It is the development arm of the business. And it holds Emera Energy Services. (Transcript, May 23/02, pp.3196-3197)

Q. And in part, that's what I was getting to, Mr. Huskilson. Fuel procurement -- we've already been through this -- fuel costs is the driver in this application and certainly fuel procurement has been made a key issue by a number of the intervenors. That's correct? A. It absolutely is, but as we've also said in the hearing, the strategy for fuel procurement and the actual purchases of fuel are done by Nova Scotia Power. Emera Energy Services acts as an agent, and that agency relationship is as we've described it.

Q. All right. But you -- let's be clear. You have touted Emera Energy -- and I'm just using those two words now rather than Services or Inc. -- but Emera Energy as having the expertise and having the ability to gather together that expertise to deliver better fuel procurement service than NSPI could execute on its own. Having said that, and given that fuel procurement is a key issue in this proceeding, we have heard from no one who is intimately familiar with the details behind Emera Energy, either Mr. Mann or anyone else. Isn't that correct? A. Yes. (Transcript, May 23/02, pp.3200-3201)

[196] In the following response to questions from the Board, Mr. Huskilson attempted to justify how NSPI, while retaining the final decision-making function relative to fuel procurement, can realize cost savings by using Emera Energy as an agent.

A. (Huskilson) The reason that it's less is because Emera Energy is doing it for less than their cost. And the reason that they're willing to do that is because they have a bigger business than our business, and that's [the] why. They can begin to employ arms and legs of people where we could not. If we had a person, we had to have a whole person. And so the cost efficiency of doing it for more people means that they can do it for less money. (Transcript, May 23/02, pp.3205-3206)

[197] In its post-hearing brief, NSPI acknowledged that: A number of questions about affiliate transactions were raised in the hearing. Because of the evolving nature of the relationship between NSPI and, in particular, Emera Energy, NSPI was not able to place before the Board a level of detail and precision about certain affiliate transactions which the Board might reasonably expect.

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(NSPI Post-Hearing Brief, p.56)

[198] NSPI further stated that: With respect to the way forward on affiliate transactions and in particular the agency agreement, NSPI has engaged expertise to advise on the appropriate structure for these agreements. Clearly the matters noted above, among others need to be addressed. Also NSPI will ensure that it can audit all transactions; that it obtains the market price for fuel and that Emera Energy will have adequate risk management strategies in place. Mr. Huskilson indicated that appropriate regulatory precedent and principle would be identified and that those would be reflected in the agency agreement. Mr. Huskilson advised that the agency agreement would be submitted to the Board. Preliminary research on behalf of NSPI indicates that there are a number of instances among significant U.S. utilities of regulated utilities having their acquisition of coal and other fuels managed by unregulated affiliated trading companies, but this information is not on the record of this proceeding. NSPI would propose to present it, together with information concerning any safeguards which were considered appropriate in these situations, in connection with the filing of the agency agreement. Mr. Huskilson made it clear that responsibility for the fuel procurement strategy and final decision making on fuel purchases will stay with NSPI. NSPI respectfully requests that the Board not take any final steps or make any final orders in this proceeding that would have the effect of precluding potentially beneficial affiliate transactions which are otherwise permitted by the Code. This would include delays in establishing any principles such as those set out in Dr. Stutz’s additional evidence or making final determinations on the appropriate fuel procurement configuration until the draft agency agreement is completed and submitted to the Board. (NSPI, Post-Hearing Brief, p.60-61)

6.2.2 Submissions - Intervenors

[199] Of the intervenors who addressed the issue, all objected to NSPI’s proposed

Agency Agreement with Emera Energy.

[200] Annapolis, through its expert witness, Ms. Medine, and in its written submissions, challenged the notion that fuel procurement is not a core function of the Utility. It further questions whether Emera Energy’s involvement in fuel procurement for NSPI is of value to

NSPI.

[201] Annapolis asserts that:

Without question, fuel procurement is core to NSPI; it represents the single largest element of NSPI’s variable costs. We learned through the hearing that not only is it being performed by an affiliate, under an undefined relationship but that fees for services are being paid without having established fair market value. (Annapolis, Closing Submission, p.49)

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[202] Further, in its rebuttal brief, Annapolis argues that:

The Board should recognize the potential as a consequence of the large number of affiliated transactions proposed by NSPI, for it to lose regulatory control over a number of important expenses incurred by NSPI. No where is this more important than in the area of solid fuel procurement. This represents the largest annual variable cost to NSPI and its ratepayers. As outlined in our post-hearing submission, there are a number of reasons for which this function ought not to be out- sourced to Emera fuels. ... At this stage, outsourcing of coal procurement to Emera has not been proven to be beneficial. NSPI has the sequence out of order. In our submission, it should have presented a final Code of Conduct with the proposed nature of the transaction with Emera and supporting evidence that it is of benefit to NSPI to the Board before embarking upon the transaction. It is inappropriate, in our submission, for NSPI to urge the protection of the status quo when the status quo has not yet received Board sanction. In our submission, the significant risks and limited rewards associated with coal trading make it unlikely for it to be beneficial to NSPI to enter into an affiliated party transaction with Emera to undertake this work on its behalf. Footnote 85 at page 60 of NSPI’s post-hearing brief lists a number of companies uncovered in "the preliminary research on behalf of NSPI" (which was not in evidence before the hearing) of U.S. utilities having coal and other fuels acquisition managed by unregulated affiliated trading companies. Even a cursory review of the lists provided suggest that these companies are distinguishable from NSPI in size, diversification and experience. (Annapolis, Rebuttal Brief, pp.14-15)

[203] ECANS, in its written submission, takes the following position:

One might argue that there is a silver lining in this matter - and it has to do with what agency actually purchases fuel for the utility. During the Hearing, there were extended discussions about affiliate relationships and why NSPI thought it best that Emera be contracted to take over coal and other fuel purchases. ECANS could see a measured value in Mr. Huskilson’s comments about Emera Energy having a ‘larger’ view of the North American energy landscape and possessed a better overall understanding of the coal markets. However, under later cross-examination by Mr. Outhouse, the question of risk associated with some North American energy trading companies was explored. The Enron debacle, wash trades, round trip trades and other undesirable activities alerted us to the fact that passing the job of fuel procurement to Emera Energy brings with it a level of risk over which ratepayers would have no influence. During this exchange of information, it became evident to ECANS that we should express concern over who procures fuel for NSPI. We feel it will be in ratepayers’ interests if fuel procurement reverts back to an in-house activity, and with it a commitment by the Company to fully train its fuel purchasing team. ECANS recommends that: 1. That as long as NSPI remains a regulated utility, coal procurement remain a direct responsibility or business unit of NSPI

2. The Board direct NSPI to develop a comprehensive coal procurement program to ensure that solid fuel purchases are optimized, minimizing risk to ratepayers and shareholders. (ECANS, Closing

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Submission, p.9)

[204] HRM reiterates this view, stating that:

HRM submits that given the risks associated with outsourcing fuel procurement, without sufficient cost reduction benefits, it is in the public interest for the Board to take a conservative approach and require NSPI to bring fuel procurement activities in-house. (HRM, Written Submission, p.30)

[205] SEB, whose closing arguments relating to coal procurement were filed in confidence, also objected to the proposed Agency Agreement and the lack of stringent controls and protocols surrounding multi-million dollar purchases.

[206] Dr. Stutz filed supplementary evidence addressing the proposed Agency

Agreement between NSPI and Emera Energy. Dr. Stutz also referred to certain remarks by Mr.

Mann at the 2002 Emera Annual General Meeting.

[207] Dr. Stutz’s supplementary evidence reads, in part, as follows:

Q. Has NSPI provided evidence justifying the development of an Agency Agreement with Emera Energy? A. No. In the course of cross Mr. Huskilson stated that Emera Energy has been able to bring in expertise and build systems that could not be justified within NSPI. However, there is no evidence concerning the incremental costs involved or the specific type and value of the benefits Emera Energy will provide.

Q. Do you have concerns about an Agency Agreement? A. Yes, I do. There are limitations as well as potential conflicts and risks associated with any such agreement. These include the following: - The Board’s ability to review all the activities of those involved in NSPI’s fuel purchasing and gas and power sales will be limited. - After becoming a central part of NSPI’s operations, Emera Energy could develop conflicts that preclude its continuation as NSPI’s agent. - Emera Energy’s unregulated activities could be quite risky. The Agency Agreement will decrease NSPI’s insulation from these activities.

Q. What sort of limitation might the Board face? A. Mr. Huskilson’s lack of awareness of Emera Energy’s “internal workings” provides an indication of the limitations the Board might face under an Agency Agreement. More generally, as Ms. McShane indicated during her cross, regulators have less access to unregulated affiliates then they do to regulated utilities.

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Q. What conflicts might arise? A. As Mr. Mann stated in his remarks, [2002 Emera Annual General Meeting] Emera Energy was formed to manage Emera’s non-utility investments and to lead Emera’s business development. The activities might, for example, include use of the turbine mentioned in the PWC report to generate electricity for sale to municipalities in direct competition with NSPI, or the purchase and resale of gas in competition with sales from which NSPI might benefit. The potential for conflict is broad because, as Mr. Mann notes in his remarks, Emera Energy will offer all the services it provides to NSPI to “other parties”.

Q. Please discuss the risks associated with Emera Energy’s activities. A. As noted in Mr. Mann’s remarks, Emera Energy will include a “highly professional trading entity which levers off our existing businesses”. In a recent article, Dr. Jay Lukens, the expert selected by NSPI to help develop the Agency Agreement, discusses such unregulated trading activities. He observes that large sums of money are being made and lost trading energy assets and commodities. He also notes that utility trading affiliates have grown very rapidly. Recently the methods by which some such utility affiliates have achieved rapid growth have become a source of serious concern. (Exhibit N-154, pp.1-3)

[208] Further, Dr. Stutz pointed out that:

The area covered by the Agency Agreement is central to NSPI’s operations. It accounts for 54% of NSPI’s cost of operations and 38% of its requested revenues in the test year. In light of the area’s importance and the limitations, risks and potential conflicts associated with an Agency Agreement, the Board should seriously consider requesting that NSPI not pursue the development of such an agreement. (Exhibit N-154, p.4)

[209] Dr. Stutz also recommended that should NSPI continue to pursue an Agency

Agreement with Emera Energy, certain principles governing the agreement should be instituted by the Board. These are as follows:

1. An Agency Agreement could increase the cost of procuring fuel, purchasing and selling power, or reselling gas. To avoid this, test year costs should be limited to NSPI’s net savings in the provision of services due to the agreement. It should be NSPI’s burden to quantify and document the savings in question, netting out any additional “oversight costs” created by the agreement.

2. Margin sharing could transfer to Emera Energy margins on power or sales that NSPI could have made on its own. To avoid this, NSPI’s revenues should include all test year margins on power and gas sales, except when NSPI can show to the Board’s satisfaction that a specific margin could not have been earned without Emera Energy’s services. Only such additional margins should be shared with Emera Energy.

3. As noted earlier, an Agency Agreement creates risks for NSPI ratepayers. As

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compensation for assuming these risks, any additional margins should be shared with ratepayers based on a split determined by the Board. (Exhibit N-154, p.5)

[210] In response to questions from the Board, Dr. Stutz stated that:

. . . What is certainly true is that as near as I can determine, NSPI is outsourcing to Emera and to others because it feels it can run the company in a more cost-effective way doing that. So I take that as a given. What concerns me is that the outsourcing of the fuel function creates limitations on your oversight, conflicts about which we won't know until it's too late to really deal with them effectively, and risks which are very hard to anticipate. And I don't think that those issues have been given due weight. Any of those issues could swamp the benefits that we see in day-to-day efficiency. Let me give you my two examples of how things get swamped. My first example is California. The thing that's forgotten about the California regulatory experiment is that it worked splendidly for a number of years before it went directly into the dumper. And so you could set up a system and run it and have it work efficiently. In fact, there's an article which appeared contemporaneously with the incredible run-up of California prices written by one of the officials who oversaw deregulation in California extolling California as the model for the world of successful deregulation. They were just hit by a train they didn't see coming. Now, let me give you the example that's perhaps a bit closer to home. I'm sure when the CEO of Consumers Power was setting up their trading subsidiary, he told people that it was going to be a boon to the company. Well, he resigned over that. I mean, it was a disaster for the company. And it's that kind of very large risk that you're creating that concerns me. I mean, just imagine the following scenario. We have Emera Energy involved intimately in the middle of a fuel procurement, something goes haywire in Emera Energy's other trading activities, there's a blowup similar to the wash trading blowup that we just saw in the U.S., senior officials depart from Emera Energy, there's some massive financial problem in Emera Energy. What kind of attention do you think your fuel procurement is going to get? Those are the kind of concerns I have. And I just don't think we can know how dangerous those risks are. You know, it's very well to say, "We'll have good financial controls. We'll do this. We'll do that." You can always deal with the problems you've seen in the past. The problem is we keep seeing new problems. (Transcript, June 4/02, pp.3992-3994)

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6.2.3 Findings

[211] The Board is troubled by the Agency Agreement between NSPI and Emera

Energy.

[212] Fundamentally, the Board is concerned that a major portion of NSPI’s fuel procurement activity, which the Board views as a core function of the Utility, representing a huge portion of NSPI’s total costs, has been effectively transferred to an unregulated affiliate with no notice, regulatory approval or formal documentation by way of contract. This is despite the fact that in the Board’s opinion, fuel procurement, gas sales and export electricity sales could well be considered as undertakings of NSPI. Section 62 of the Act reads as follows:

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.

[213] The Board notes that in Undertaking U-102 NSPI has declined to provide its legal opinion on a confidential basis in this matter, while indicating that further “information” will be forthcoming.

[214] The Board finds that the manner in which NSPI has conducted itself with respect to the Agency Agreement is not in keeping with the spirit and intent of the utility regulatory regime in this Province. The Board is of the view that the parent company of NSPI wishes to transfer to Emera affiliates many functions and activities which are carried out by NSPI. The Board is concerned that these activities could lead to a reduction in income to NSPI, thereby resulting in an increased burden on its ratepayers.

[215] The Board’s concerns are heightened because it appears that NSPI is

Document : 78377 89 embarking on a course of action without having fully considered its ramifications. An example is

NSPI’s request to transfer the Shell gas contract, at no value, to Emera Energy. The contract, along with Dr. Lukens’ justification for its transfer, was provided to the Board some considerable time after it was initially requested. When the Board issued formal information requests (which, among other things, questioned how NSPI could justify transferring the contract to Emera Energy with no value attributed), no response was forthcoming from NSPI. Instead, the Board learned for the first time at the hearing that the request to transfer the Shell contract to Emera Energy had been abandoned. The Board’s concerns are further exacerbated by the inability of the NSPI witnesses to answer questions concerning the details surrounding the operations of Emera and its affiliate companies.

[216] There are a number of reasons to have reservations about the Agency

Agreement. Since no document was available to the Board during the proceeding, the intended terms of the agreement were unknown. Similarly, in the Board’s opinion, there is little or no reliable evidence in this proceeding that NSPI would benefit as a result of the agreement. NSPI justifies the estimated $672,000 in fees to be paid to Emera Energy in 2002 by submitting that, because Emera Energy performs these services, NSPI’s costs are lower than they otherwise would have been. The difficulty arises when one attempts to quantify this “benefit” without knowing whether NSPI’s fuel procurement division was as efficient as possible prior to divestiture.

[217] NSPI’s suggestion that coal costs could be lowered through volume discounts available to Emera, but not NSPI, was ably refuted by Ms. Medine. While clearly reluctant to contradict his client, NSPI’s own coal expert, Mr. Watkins, was unable to fully endorse this

Document : 78377 90 proposition in his evidence before the Board.

[218] Moreover, NSPI’s confidential Undertaking U-90, which lists the “other

customers” of Emera Energy, does not give the Board confidence that NSPI will benefit from

participating in Emera Energy’s purchasing pool.

[219] Quite apart from NSPI’s inability to demonstrate cost savings as a result of the

Agency Agreement, there are valid concerns that the potential exists for Emera Energy and NSPI to

have conflicting interests. As pointed out by Dr. Stutz, the potential also exists for Emera Energy to

compete with NSPI:

As Mr. Mann stated in his remarks, Emera Energy was formed to manage Emera’s non-utility investments and to lead Emera’s business development. The activities might, for example, include use of the turbine mentioned in the PWC report to generate electricity for sale to municipalities in direct competition with NSPI, or the purchase and resale of gas in competition with sales from which NSPI might benefit. The potential for conflict is broad because as Mr. Mann notes in his remarks, Emera Energy will offer all the services it provides to NSPI to “other parties”. (Exhibit N-154, pp.2-3)

[220] The Agency Agreement seems to reflect a pattern of transactions whereby

activities previously performed by NSPI are transferred to affiliates. These transfers are not the

subject of competitive bids. It is unclear whether the affiliates can perform the tasks better than

NSPI since no evidence is forthcoming from the unregulated entities. This has been the case with the

sale of steam to Strait Energy; the aborted transfer of the Shell contract; the buy-back of refurbished

transformers; as well as the Agency Agreement with Emera Energy.

[221] The Board also notes the qualifying comment made by NSPI’s auditors in their report to the Board concerning their review of affiliate transactions:

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Significant Interpretations We have audited the compliance of Nova Scotia Power Inc. (NSPI) for the period of September 16, 2001 to December 31, 2001 with the criteria established and described in the NSPI Interim Code of Conduct (the “Code of Conduct”) dated March 16, 2001 with the Nova Scotia Utility and Review Board. Compliance was evaluated within the framework of significant interpretations determined by NSPI’s management and summarized below. Fair Market Value of Emera Energy Transactions NSPI currently sells power to Emera Energy using a sharing mechanism that management believes represents fair market value. (Exhibit N-99, Ernst & Young Report)[Emphasis added]

[222] In the Board’s view, fair market value cannot reasonably be established on such a subjective basis. This arrangement is unsatisfactory as it is open to abuse.

[223] After considering all of the evidence concerning this matter, the Board is not satisfied that, given the present structure of NSPI and Emera, ratepayers will be adequately protected from Emera’s apparent intention of levering off NSPI for the benefit of Emera shareholders.

[224] Accordingly, the Board disallows all fees paid by NSPI to Emera Energy in the test year for fuel procurement services, export electricity sales and gas sales as being imprudent.

Furthermore, the Board directs that NSPI resume full responsibility for its own fuel procurement, export electricity sales and gas sales which the Board considers to be core functions of NSPI and an undertaking of the Utility pursuant to Section 62 of the Act. There may be some point in the future when it would be prudent for these functions to be out-sourced, but this is neither an appropriate time, nor are these appropriate circumstances to consider doing so. No information or evaluation of

Emera’s ability, performance and track record relative to other service providers is available to the

Board and there are valid concerns relating to risk, conflict and harm to ratepayers should these functions be performed by an affiliate.

[225] To the extent that there are costs to NSPI associated with this directive, the

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Board finds that such costs are as a result of the transfer of an undertaking of the utility without the required approval of the Board. Under the circumstances, the Board does not believe it is reasonable for the ratepayers to shoulder this expense.

[226] The Board also directs NSPI to engage the services of experts in the area of fuel procurement, especially coal, to develop in-house fuel procurement expertise, formalized policies and procedures governing fuel purchases. The Board finds Ms. Medine’s evidence particularly helpful in its deliberations in this matter. Although the Board will not quote directly from evidence given during in camera sessions, suffice it to say that the Board shares Ms. Medine’s view that neither NSPI nor Emera appear to have proper procedures or practices in place to control and govern annual coal purchases of approximately $200 million. NSPI is further directed to report to the Board on the status of its in-house fuel procurement division and policy and procedures development within six months of the date of this decision, and to provide a follow-up report six months later.

[227] The Board further directs that prior to the future transfer of functions which, in the opinion of the Board, could constitute an undertaking of the utility, NSPI must receive the approval of the Board.

[228] On October 8, 2002, NSPI filed, on a confidential basis, a copy of an executed

"Agency and Surplus Energy Purchase and Sale Agreement" between Emera Energy and NSPI.

NSPI has not requested approval of the Agreement and takes the position that none is required. As is

apparent from the foregoing, the Board disagrees. Further, the Board is not satisfied on the evidence

that any fees or commissions paid by NSPI to Emera Energy pursuant to the Agency Agreement are

Document : 78377 93 reasonable or prudent in the circumstances and, accordingly, such fees will not be chargeable against ratepayers.

[229] Based on the information available to the Board this will result in a reduction

of at least $672,000 in the revenue requirement. The Board directs NSPI to provide, as part of its

Compliance Filing, all fees paid in the test year by NSPI to Emera Energy with respect to fuel

procurement services, export electricity sales and gas sales in order for the Board to determine the

precise amount to be disallowed as a result of this ruling.

6.3 Shared Services Allocation

6.3.1 Submission - NSPI

[230] NSPI uses the “four-factor” allocation method to determine the portion of the cost of services shared with its affiliates to be borne by NSPI. The method is described by NSPI’s auditors in Exhibit N-99:

Management has adopted the four factor allocation method to allocate its Corporate costs to all companies within the Emera consolidated group. The four factor allocation method uses an average of the pro-rata percentage of Emera’s consolidated assets; revenues; operating, maintenance and general expenses; and earnings before interest and taxes. (Exhibit N-99, Ernst & Young Report)

[231] In Exhibit N-1, NSPI states that:

... NSPI has adopted a simple, understandable and cost effective approach to cost allocation in accordance with the Code of Conduct. The Company has used an allocation methodology using an average of the pro-rata percentage of Emera’s consolidated assets, revenues, OM&G and earnings before interest and taxes. Similar approaches have been used by other utilities in North America. The total pool of corporate costs that are projected to be allocated using this approach are $16.0 million and $18.6 million in 2001 and 2002 respectively. The increase is driven primarily by increased labour costs and the full year impact of filling positions vacant for a portion of 2001. Using this approach, NSPI will be charged 83% or $13.3 million of the corporate support

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costs in 2001. In 2002, this percentage will fall to 73% ($13.6 million) as more companies join the Emera group (in particular Bangor-Hydro) and the cost of corporate support services is shared across a broader base. (Exhibit N-1, pp.20-21)

[232] NSPI witnesses have argued that this formula is simple, effective and time- saving as opposed to other methods such as time allocation. In its post-hearing brief, NSPI asserts that:

While there are many different ways to allocate cost NSPI submits the current four factor method is as good as any and is similar to that used elsewhere in North America and more importantly results in a fair allocation of corporate costs. Indeed, this methodology is frequently resisted by utilities on the grounds that it attributed too much cost to the non-utility elements of the company. Utilizing a differing allocation basis for various corporate support groups may result in a different measure than currently identified, but this does not equate to a more “accurate” allocation of costs. By definition, much of the time spent by senior executives are truly joint or common costs of the whole enterprise. They are not uniquely attributable to any segment of the business, and allocations are necessarily arbitrary. Further, executives are not professionals or consultants who are compensated on the basis of hours spent. Rather, they are compensated on the basis of the responsibilities which they bear, and the proposed formula is a reasonable proxy for those responsibilities and a reasonable allocator of executive cost. The simplicity and transparency of the current method of cost allocation outweighs any benefit NSPI believes which may be obtained from changing the costing methodology as noted by Ms. Redden. . . . It is submitted that one must step back from the issue and determine how much time, effort and cost should be “allocated" to allocating $18,000,000 worth of corporate costs. Ms. Redden specifically notes the impact of consultant’s recommendations with respect to human resources and accounting. If the PwC recommendation were implemented more cost for those departments would be allocated to NSPI. (NSPI, Post-Hearing Brief, pp.43-44)

6.3.2 Submissions - Intervenors

[233] Annapolis, in its closing submission to the Board, objects to the cost

allocation methodology used by NSPI, asserting that:

It is submitted that the allocation methodology should be of concern to the Board. While NSPI trumpeted that the percentage of shared cost is declining for NSPI in relation to the overall costs of Emera in 2002 from 2001, in fact the actual cost to NSPI is increasing by approximately $300,000. It is however very difficult to track the increased costs due to changes in structure of the entities, changes in responsibilities and movements of personnel. It is submitted that the lack of transparency regarding shared services should be of concern to the Board and, it is recommended that another “fair” allocation methodology be adopted to track actual time and effort.

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(Annapolis, Closing Submission, p. 59)

[234] HRM, ECANS and the Province also object to NSPI’s current cost allocation methodology.

[235] PWC, in its report, stated that it did not believe the “four factor” allocation method was fair, noting that:

... We do not believe that the measurements used provide a fair basis for the allocations. The following are examples of where the allocations may not be fair: - New and growing businesses (e.g., Emera Energy) typically require more management time than mature businesses (e.g., NSPI). The formula’s focus on revenues and income actually gives the reverse impact with relatively high allocations to the mature businesses. - The formula does not deal with unusual transactions. For example, the acquisition of Bangor Hydro and the investment in the Sable Offshore Energy Project in 2001 would undoubtedly have taken significant amounts of senior management, general counsel and treasury/finance time. This is not reflected in the formula. - We would have anticipated that NSPI would have been allocated a relatively small amount of Emera executive management costs as NSPI has its own executive team in place. This does not appear to be reflected in the formula. We understand that NSPI wants to implement a formula-driven approach as it believes that the overall dollars to be allocated are relatively small and it wants a simple solution. (Exhibit N-19, p.6)

[236] PWC recommended that:

... NSPI and Emera review and implement alternative methods of allocating its corporate support service costs. We believe that the methods chosen should relate to the amount of the specific service being provided to or being used by each entity. We believe that this will result in different measures being used to allocate different costs. (Exhibit N-19, p. 7)

[237] Dr. Stutz said the following when asked by the Board to comment on NSPI’s

use of the “four-factor” methodology for cost allocation:

... I understand the convenience of the formula and I understand that it may be a widely-accepted formula. I've spent 25 years in the accounting -- in the consulting business, and during those 25 years I've accounted for my time hour-by-hour each week and I've never found it burdensome, I've never found it to interfere with my business operations. I routinely take recent college graduates and in the space of about a quarter of an hour explain to them how to fill out the form required to do that. So, I don't see a direct assignment as burdensome. Now, admittedly I'm not dealing with an organization which is at the scale of Nova Scotia Power, so scale may be an issue to consider there, but my personal experience is it's not a problem. My sense from talking to people who work in large law firms is they

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don't find it a problem either and they have software that makes it quite easy, as do we. There is an issue of fairness, which I think is raised in the PricewaterhouseCoopers report. I would think it would also be useful to the Board to have some clear understanding of who's spending how much time doing what for whom, and direct assignment, were you to be able to audit that at some point, would give you that kind of information. So, if that's of interest to you, that might influence the methodology you choose as well. (Transcript, June 4/02, pp.3921-3922)

6.3.3 Findings

[238] There are two issues to be determined in reviewing NSPI’s cost allocation

model. Firstly, is the “four-factor” method the most fair and reasonable approach? Secondly, is it

fair to apportion 73% of 2002 corporate costs to NSPI?

[239] With respect to the first point, the Board agrees with PWC that the current

method may result in unfairness. The ratepayers currently bear the risk of the potential for unfairness

as some senior management members are engaged in fostering new businesses on behalf of Emera

while NSPI ratepayers bear the lion’s share of corporate costs.

[240] The Board is of the opinion that, with respect to senior management, properly

documented time allocation is the most appropriate method to determine how costs should be shared.

This is the best way to demonstrate that ratepayers are only charged for effort expended on their

behalf in respect of NSPI functions.

[241] In reaching this conclusion, the Board recognizes NSPI’s comments regarding

the relative materiality of the amounts involved. Again, the Board is of the opinion that the

principle is more important than NSPI’s materiality threshold. NSPI ought to be able to demonstrate

fairness to the ratepayers in the manner in which it conducts its affairs. It may well be that

executives are inconvenienced in pursuit of fairness. In the Board’s view, the requirement for

fairness and accountability overrides any inconvenience.

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[242] The Board expects that senior management of NSPI generally plan in advance their daily activities, and the recording and allocating of such activities should merely be an extension of their daily planning. Accordingly, the Board directs NSPI to proceed to implement a cost allocation method, to be in place for the year 2003, based on well documented time keeping records for those senior management employees having shared responsibilities for NSPI and any of

its affiliates.

[243] For those costs which cannot properly be allocated on a "time allocation"

basis, the Board accepts the recommendation of PWC that NSPI review and implement alternative

methods of allocating its corporate support service costs. The specific methods chosen should be

based on measures that are specific to the particular units, such as space, number of employees, etc.

Prior to the implementation of the specific allocation methods, NSPI should prepare a report and

submit it to the Board for approval. This report should also include a list of those senior management employees who will be accounting for their daily time and activities. In view of the

Board’s direction to NSPI to modify the four factor methodology on a go-forward basis, the Board, despite some misgivings, will accept the 73% allocation of shared costs for 2002.

6.4 Coal Transportation Costs

6.4.1 Submission - NSPI

[244] The surface assets of CBDC, which were used to transport coal for NSPI, have been acquired by an NSPI affiliate. While the future ownership of these assets is in question, NSPI has included CBDC’s charges to NSPI for coal transportation as a proxy for test year purposes.

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Under cross-examination by counsel for Annapolis, Mr. Huskilson gave the following explanation of the sequence of events involving the acquisition of these assets:

I guess, first of all, it's important to note that that is very critical infrastructure to the security of supply of the system at the Lingan and Point Aconi plants and so we -- when we understood that CBDC was closing those facilities from May, 2000 to 2001, we began to work with CBDC to try to deal with what that was going to mean and how it was going to work. We really were only informed in the fall that, in fact, CBDC was going to stop operating those assets by December the 15th and so from early in the fall until December the 15th we had to act quite quickly in order to secure the ability to operate those assets. In fact, the -- from a timing perspective, the assets were abandoned by CBDC on December the 15th and had to be operational again on January the 2nd to move coal to the plants and also to -- ultimately to allow us to receive a ship, I think, on something in around the January the 14th date. So there was a lot of work that had to be done to make that happen, a lot of logistics that had to be worked through. So since it was critical infrastructure and certainly not something that the utility was core to its responsibility anyway, we engaged one of our affiliates to do the work necessary to be able to pull this together and to make it work. And so we transferred the responsibility to pull that together to our utility -- or sorry, Emera Utility Service. They were able to get the assets working on the January time frame and started an evaluation as part of the agreement with CBDC of the value of the assets because that was not known until an evaluation was completed. And we're in the process -- we have just concluded the evaluation process as we speak and so now we're currently looking to bring these assets forward before the Board to have the Board understand from an overall perspective what the cost is of supply was critical in that case, we had to act quickly and ensure that these assets were operational. (Transcript, April 26/02, pp.962-963)

[245] Mr. Huskilson also testified that CBDC had in excess of 100 employees

engaged in operating these assets. The following exchange between Mr. Huskilson and Counsel for

Annapolis describes the current relationship between NSPI, Emera Utility Services and the

contractors:

Q. And as part of the transaction, has NSPI offered employment to any of these 100 employees? A. My understanding is that about 43 of those employees have now been employed to do work on those assets and, as well, we’ve employed a number of different contractors to do work as well, so there is a combination of contract work and direct employees that are engaged in this activity.

Q. From the sounds of your last answer, it would seem that the labour charges to be incurred by NSPI in operating these ground transportation assets would differ substantially than those of CBDC. A. Yeah. At this point, none of the employees actually work for NSPI. They actually all work for the contractors engaged in doing this work and the transfer of the collective agreements and the negotiation of the collective agreements was all done by the contractors so, in fact, NSPI's relationship right now is an agency relationship.

Q. Are any of these contractors affiliates of NSPI?

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A. Yes. At this point, Emera Utility Services is still performing the function of overall management of the facility and, again, that's something that we need to sort out as we go forward. We've really just concluded an understanding of the -- a complete understanding of the assets and a complete understanding of the value of the assets, so that's all still to be sorted out. The critical nature of the assets meant that we had to act very quickly because ensuring security of supply was the most important very similar to the Emera Utility -- the Emera Energy situation where we're in an ongoing, evolving relationship. The same thing is true here. It's going to be important that we develop a relationship that works for the utility, that meets the code of conduct and that allows us to do this in the most efficient way possible.

Q. When were the assets operational under NSPI? A. With the agency relationship in place the assets went operational January the 2nd. The assets would have been transferred from CBDC on December the 15th, I believe.

Q. And at present, is NSPI paying Emera Utility Services for its services in connection with these assets at the same rate that it was remunerating Devco in the past? A. Again, I'd say that we're in about the same situation with this as we are with Emera Energy in that we have an agency relationship but we're evolving the cost because we haven't actually understood exactly what we can get a cost. A very significant question is what is the [demurrage] charge that will actually occur as a function of the operation of these assets. When CBDC was operating them, we were paying almost two and a half million dollars ($2,500,000) a year in demerge [demurrage] charges. Emera Utility Services believes that they can substantially improve that number. And so we're in the process of really working through what kind of costs we're going to incur here. At this point, we've said that the best we know about it is that for, I think, a slightly increased tonnage, we believe that we can operate the facilities in and around the cost that was there from last year, and so the revenue requirement includes that cost. But as we go through the year and as we go through our circumstance, we'll understand better the cost of operating. Q. Who's paying the workers right now? A. The workers are actually being paid by Logistech, which is a third party agent engaged in the activity.

Q. Who's paying Logistech? A. Emera Utility Services.

Q. And who's paying Emera Utility Services? A. Nova Scotia Power is paying through the agency relationship. (Transcript, April 26/02, pp.965-968)

[246] Mr. Huskilson indicated that a request for Board approval for NSPI to acquire these assets would be forthcoming along with updated information with respect to NSPI’s costs of coal transportation as compared to CBDC.

6.4.2 Submissions - Intervenors

[247] MEUNSC notes in its rebuttal brief that:

Document : 78377 100

On page 18, lines 17 and 18 [of NSPI’s Post-Hearing Brief], NSPI states that it has proposed to deem the price recently paid to CBDC for rail and truck freight within Nova Scotia as an arms- length price, for the purpose of “the regulated revenue requirement”. Given that under the Contract with CBDC the ground freight was included as part of a price for coal that NSPI vigorously disputed, to the point of withholding payment, and given the testimony of NSPI witnesses on Devco inefficiencies and the Confidential evidence in the J. T. Boyd analysis, it is difficult to accept that this price is a reasonable surrogate for a market price. Or that it is a price that NSPI would willingly pay to a non-affiliated firm. If NSPI believes that the CBDC transport price is fair and reasonable, they stand alone in this belief. Expert testimony by both Ms. Hennings and Ms. Medine held that this cost was too high. (MEUNSC, Rebuttal Brief, p.2)

[248] ECANS states that:

ECANS objects to the assumption that previous CBDC transportation rates are deemed to be in the best interest of ratepayers. For years, NSPI complained about the expensive, non- competitive costs CBDC inflicted upon electricity users in this Province. But when an opportunity presents itself for NSPI to eliminate this decades-old practice, it chose to set a legitimate concern aside in favour of furthering the financial well being of an affiliate. If NSPI had acted with its ratepayers in mind, these services would have been tendered thus ensuring best value for money and least costs to consumers. (ECANS, Response to Final Submissions, p.3)

[249] While SEB’s comments on the CBDC transportation assets are part of its confidential filing, it, too, asserts that given the uncertainty regarding the ownership of the assets,

NSPI shareholders, not ratepayers, should bear the responsibility for these costs. SEB further argues that by simply adopting CBDC’s high prices, NSPI has made no effort to control transportation costs itself despite now having an opportunity to do so.

[250] SEB’s expert, Ms. Hennings, suggested that a significant reduction in NSPI’s coal transportation costs are warranted. Also, PWC notes in its report that:

NSPI indicated that it transferred the option to its affiliate, Emera Utility Services, for $10 consideration. We now understand that NSPI will apply to the Board to acquire these rail assets but that the intent is that Emera Utility Services will manage the railway for NSPI. No pricing has yet been set for this latter contract. We believe that the pricing should follow either Section 6.8 or Section 6.9 in the Code of Conduct. Transfer pricing methodologies may be employed to ascertain fair market value of these services. Caution should be used before assuming that transportation charges from Devco represent fair market value. The Devco contract was for both the supply and delivery of coal. Often, in multiple-element contracts, the buyer and seller both look at overall price and not at the individually quoted prices. The transfer of the assets to NSPI will transfer most of the risks associated with establishing a rail transportation business to NSPI and the ratepayers. We believe that any management contract pricing should reflect this risk transfer. We also note that the purchase option transfer from NSPI to an affiliate was not on the list of

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affiliate transactions nor was there any indication that fair market value of this option was assessed. While we understand NSPI’s position that unregulated activities should be carried on outside of NSPI, where those opportunities arise within NSPI, the Code of Conduct applies to their movement. (Exhibit N-19, p.23)

6.4.3 Findings

[251] The Board notes the objections of the intervenors to the use of CBDC prices to support NSPI’s test year estimate for coal transportation costs. The Board further notes that no request of the nature described by Mr. Huskilson, supra, has been filed with the Board to date.

[252] The Board considers that it is not reasonable to use CBDC’s charges to NSPI as representative of the test year cost of the transportation work formerly performed by CBDC. In the Board’s view, it is reasonable to expect that NSPI or its affiliate should operate the surface assets during the test year at a lower cost than CBDC did. Having reviewed the evidence and bearing in mind the comments of PWC with respect to the appropriate fair market value of CBDC’s transportation charges, the Board will reduce NSPI’s deemed expense for the use of the CBDC surface assets by $2 million. NSPI’s revenue requirement is reduced accordingly. Given its concerns arising from Ms. Hennings’ evidence, the Board is of the view that this is a conservative adjustment.

The Board wishes to be satisfied that NSPI will be paying fair market value for the use of these facilities in the future. NSPI is directed to file information supporting its transportation expenses relating to these facilities within six months of the date of this decision. If the Board is not satisfied with this information, it reserves the right to engage suitable consultants to advise it concerning the fair market value of NSPI’s expenditures with respect to these facilities.

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6.5 Independence and Insulation

[253] The Board became increasingly concerned during the hearing with respect to

the apparent lack of separation between NSPI and Emera and how this could negatively impact

ratepayers.

[254] NSPI, as a corporate entity, has significant assets. Its monopoly status places

it in a powerful position. Over the years, ratepayers have paid for the construction and operation of

generating stations, transmission lines and distribution systems, indeed all of the plant required to

serve customers.

[255] Emera is in the process of developing many affiliated unregulated businesses,

leveraging off its existing businesses. Its principal existing business is NSPI which accounts for in

excess of 80% of Emera’s revenue. While this may change in the future with the acquisition of

Bangor Hydro and other businesses, NSPI presently constitutes the predominant source of Emera’s financial strength.

[256] It is imperative, in the Board’s view, that NSPI and Emera avoid becoming so

integrated that senior management is conflicted between the interests of Emera’s shareholders and

the interests of NSPI ratepayers. It is clear to the Board that these interests can diverge from time to

time. What is unclear to the Board is whether NSPI has the appropriate management structure to

protect ratepayers in such circumstances.

[257] According to Mr. Huskilson, and confirmed by Undertaking U-107, many of

NSPI’s personnel, including its most senior executives, also have responsibilities relating to Emera

or Emera affiliates. This fact, coupled with the apparent trend to spin off functions of NSPI to Emera

affiliates, reinforces the Board’s concern that some inherent separation is necessary.

[258] The Board does not wish to limit Emera’s legitimate business development

Document : 78377 103 initiatives, nor does it wish to prevent NSPI from achieving worthwhile efficiencies. Neither does it wish to impose impractical restrictions on the relationship between NSPI and Emera. However, the

Board must be satisfied that utility’s assets are not transferred to affiliates without appropriate approval, regulatory oversight and objective arm’s length valuation.

[259] The Board has carefully considered the evidence of Mr. Falconer, Dr.

Kryzanowski and Dr. Stutz on the issue of “insulation” - the degree to which the utility is separated, or insulated, from its affiliates.

[260] Mr. Falconer said the following in response to Board questions concerning

Exhibit N-47, a research report by Standard and Poor’s dated January 23, 2002, in which NSPI was described as lacking sufficient regulatory insulation:

A. As soon as I saw this document some weeks ago, I latched onto exactly the same sentence and spent considerable time trying to analyze exactly what they were looking at, and I think the concern here they're looking for is the degree to which you can be assured that the activities of Nova Scotia Power are -- "ring-fenced" is a word often used NSPI itself freestanding and itself controlled by the board and by the actions of NSPI independent of Emera. I think that's what they're getting at and I think that's a fair and valid point one always looks for in the evolution between a holding company and a subsidiary. We face exactly the same issues as a bank when we look to lending or look to do financing of any freestanding entities. So, this is a fairly common phenomenon that we face all the time. Most financing, say, by a bank to an entity that's held by somebody else is not -- they are not interlinked, and so you're always questioning, "Well, how is that freestanding entity looked at and is it fair, the relationships between that and the holding company, and in particular, is it protected against any developments from the other entity?" So, as a lender we look at exactly these same issues.

Q. It appears that S&P have looked at this in coming to the conclusion that there is an insufficient regulatory insulation in this case. A. That's the way I read the sentence as well.

Q. In your experience is it the norm or is it the usual that there would be an independent board of directors in these types of circumstances? A. Probably not at this stage of development. I would use the analogy of what has been happening with the setting up of a lot of these trust units in the capital markets these days. I'm sure you've all heard of these, where you do these -- carve out a piece of the business and finance it separately as an income trust, and those are often very much interlinked like this. They're often a fundamental part of the business that is separately financed. And if they have a separate economic interest, then often you do look at independent board members, although in those cases often it's relatively few of the board members. Say, there might be five, seven board members, there might only be two or three that are independent, but that is a factor that is looked at

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by other financial people in similar circumstances.

Q. Do you think that would be a prudent move, that is at least a partially independent board of directors if some of the activities, in fact, posed competition to the utility? A. I would suspect that -- well, I find it extremely dangerous to speculate, especially in a public forum, as to how a client should conduct its business. So, with that as a preamble, my answer would still be yes. My partners at my firm may not appreciate it.

Q. And in terms of light-handed regulation -- and that's kind of a pleasant surprise because in past proceedings, one, I think, anyway, the word "draconian" may have been used. But light-handed regulation, I guess in this instance -- do you take that to mean there is no requirement that the utility come before the Board on an annual or twice-yearly basis to be reviewed? A. To be honest, I had a little difficulty with that comment because it was the circumstances that dictated that there was not a hearing on a regular basis. I took it as a positive comment, or meant as a positive comment by this commentator. I didn't see the justification for it, to be honest, but that's a personal view. (Transcript, May 13/02, pp. 1999-2001)

[261] The comment in the Standard and Poor’s report which gave rise to the above exchange read as follows:

The ratings on Nova Scotia Power reflect the company’s combined business and financial risk profile and are determined in conjunction with the credit quality of parent Emera. The parent and operating company credit profiles are further linked because ultimately Emera is responsible for maintaining a common equity thickness at the regulated electricity utility operations. Given a lack of sufficient regulatory insulation (light-handed, reactive regulation; minimal restrictions on dividend payouts; and no independent board of directors), the ratings on Nova Scotia Power are equalized with those on Emera. (Exhibit N-47, p. 3)

[262] Dr. Kryzanowski, in response to questions from Board Counsel, stated that:

In terms of making sure that transfer pricing is appropriate between the parent and the sub, making sure that the profits are not transferred to the parent and the risks remain with the sub, ensuring that the parent is a tower of strength for the sub. I mean, this is a major problem in the banking area, and Gordon and I did a study for the government in terms of that, and basically you want to make sure that NSPI is not affected adversely by actions at the parent. (Transcript, May 15/02, p. 2330)

[263] Dr. Kryzanowski went on to say that:

I guess we could make a more general comment. There's a lot of discussion in Canada about corporate governance, and corporate governance in Canada is a major problem. If you look at Boards of Directors, there's been studies in terms of what should the Board of Directors be. And the TSE hasn't gone that far, but they've gone part of the way and they feel that the majority should be independent Directors. Now, when you start moving to parent and subsidiaries, in some cases you don't even have a Board for the sub or the majority of Directors are not independent.

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(Transcript, May 15/02, p. 2393)

[264] Dr. Stutz also referred to the issue of insulation, commenting that:

I haven't looked to see whether there are separate Boards of Directors. I would think over time that would be something that would be considered. Given the extent to which NSPI makes up Emera at this time, I wouldn't have expected a separate board in the past. After all, it was 90 odd percent. I can't see how you would in that situation go for it. Now, we've heard many more Emera activities are coming on line. There's the gas storage. I don't know what else might come in the future, but certainly as Emera gets larger and as the non-NSPI portion of Emera grows larger, then there would be more of a case for it, I would think. (Transcript, June 4/02, p. 4000)

[265] The Board also notes the concerns of the intervenors, some of whom have referenced the recent and well publicized problems experienced by investor-owned energy companies as a result of affiliate activities.

[266] NSPI, in defence of its affiliate activities, asserts that:

In the current open access market in North America there are enhanced risks associated with exporting and trading in electrical energy. Companies conducting that activity have to understand the business and have specialized skills to do the business. Having trading activity within NSPI creates risk. Trading in both electricity and fuels has to occur. The spectre of Enron and other companies hung over the hearing created by the introduction of newspaper articles put to NSPI in cross-examination which frankly do not put those issues in proper context and adequately explain them. NSPI’s is not a situation analogous to Enron. The recent failure of Enron and the investigations into “wash trading” by many of the firms trading power have painted a picture of reckless capitalism with collateral damage to everyone involved when failures do occur. This picture is not accurate. History has shown there obviously are risks in trading, but regulated utilities dealing with un-regulated trading companies (affiliated or not) do not share in those risks to any significant extent. (NSPI, Post-Hearing Brief, pp.58-59)

[267] The Board does not view NSPI or Emera’s activities as being analogous to those carried on by Enron or by other energy companies such as Dynegy and Williams. However, these examples do give rise to legitimate concerns.

[268] In view of Emera’s intention to engage in diverse businesses, it is incumbent upon the Board to ensure ratepayers are shielded in the event that Emera is unsuccessful. While the

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Board does not believe it is necessary for each company to have a separate Board of Directors at this time, it does believe certain changes in corporate governance would enhance the degree of insulation between NSPI and Emera. Accordingly, the Board directs that effective for the year 2003:

1. Emera and NSPI use different auditing firms; and

2. NSPI’s audit committee shall have a different Chair than Emera’s audit

committee.

[269] The Board will continue to monitor this situation to determine what, if any, further changes should be made in the future.

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7.0 COST OF SERVICE, RATE DESIGN AND OTHER RATE-MAKING ISSUES

7.1 Overview - Rate-making Issues

[270] This section deals with NSPI’s translation of the revised revenue requirement into rates. The revenue requirement approved by the Board is substantially lower than the revenue requirement requested by NSPI and, consequently, the resulting rates will also be lower than those proposed by NSPI. However, because the changes from NSPI’s proposed revenue requirement are numerous and substantial, it is impossible to foresee precisely what rates these changes will produce.

To avoid the introduction of anomalous or unintended effects, NSPI is directed to submit a

Compliance Filing, providing the information identified in the following three sections.

Implementation of rates pursuant to this decision will only take place after the Compliance Filing has been reviewed by the Board, any requested modifications have been made, and the Board has issued a final Order approving the rates. Sections 7.2, 7.3, 7.4 and 7.5 set out the principles, methods and data choices that will determine the rates NSPI is directed to develop in the Compliance Filing.

[271] As noted above, the Compliance Filing will incorporate the adjustments and directives which are set out in this decision. The issues giving rise to the Board’s adjustments and directives have already been the subject of a lengthy public proceeding as have the Company’s proposed changes in rate structure. Intervenors have had a full and fair opportunity to challenge

NSPI’s application and present their own positions through evidence and argument. Accordingly, the Compliance Filing will be reviewed by the Board alone prior to the issuance of a final Order in this matter. In the Board’s view, no purpose would be served by prolonging this proceeding by permitting further representations from intervenors.

Document : 78377 108

7.2 Cost of Service Study

7.2.1 Submissions - NSPI

[272] As part of its evidence in this proceeding, NSPI filed a Cost of Service Study

(COSS). NSPI’s study is described briefly in the text to Exhibit N-1, with supporting detail in

Appendix 2. In NSPI’s evidence and also in its response to UARB-IR-92, NSPI indicated that it had relied upon the COSS methodology previously approved by the Board.

In its response, NSPI stated:

The cost of service study filed with our application on December 18, 2001 employed the same methodology as was approved by the Board in their Generic Hearing Decision dated September 20 [22], 1995. In that decision, the Board ordered that NS Power employ the 3 Coincident Peak Demand responsibility and to use the System Load Factor to allocate generation and transmission fixed costs to energy.

The only change in methodology is the allocation of Marketing and Sales costs. In 1995, these were allocated based on the number of customers in each class. In this application they are allocated based on resources dedicated to each rate class. (NSPI’s response to UARB IR-92)

[273] The current approved methodology was adopted as the result of a Generic

Hearing, which led to an Order dated September 29, 1995. The Board reaffirmed its support of that methodology in its Order in NSPI’s last rate case, dated March 4, 1996.

7.2.2 Submissions - Intervenors

[274] Two witnesses —Dr. Rosenberg and Dr. Stutz— addressed NSPI’s choice of methodology for its COSS. Dr. Rosenberg summarized two changes in his opening statement which he characterized as “improvements” to the methodology for allocating generation and transmission- related costs. He said the following:

Document : 78377 109

However, I do put forward two changes to the Company allocations that I believe improve the accuracy of the study, but are nevertheless within the confines of the 1995 Decision. The first such change deals with the allocation of fuel cost. As the Company noted on several occasions, perhaps most recently in its September 30, 2001report to the Board on its Fuel Hedging Program, fuel costs are measurably higher in the high load or on-peak hours than during the low load or off peak periods. Unfortunately, not only does the Company fuel allocation fail to capture that important factor in cost causation, it even leads to counterintuitive results, such as classes with more off-peak usage being assigned higher fuel costs per kWh of generation than classes with more on-peak usage. To resolve this problem, I projected monthly on-peak and monthly off-peak marginal fuel costs to shape a class fuel allocator in the cost of service study. If we confine ourselves to fuel costs, this would be equivalent to performing a marginal cost of service study, and then reconciling the result to the embedded revenue requirement by a uniform pro-rata reduction. In other words, if a class is found responsible for X% of the marginal fuel cost, it is also held responsible for the same X% of the embedded or average fuel cost. I explain in my testimony why this method is more reflective of cost causation, and sends more accurate price signals, than does the Company method. The second change I made to the methodology is to use this fuel allocator that I have just described, to allocate the deemed energy related portion of the generation and transmission fixed costs. In other words, the energy related portion of the fixed generation and transmission costs are allocated in a manner that exactly parallels how the paragon of energy related costs - fuel costs - are allocated. I believe that the two changes described are completely in accord with both the letter and spirit of the 1995 generic decision. More importantly, however, they represent a very modest step toward making the cost of service study more reflective of actual cost causation, and sending a more accurate price signal to customers in terms of the link between consumption patterns and consequences to the cost of service. (Exhibit N-117, pp. 16-17) [275] Dr. Stutz suggested the possibility of a change in the classification and allocation of certain distribution system costs which, he acknowledged, would be a change from the

Board’s previously approved methodology for dealing with these costs.

[276] In addition to methodology, the results of a COSS depend on the data, particularly the costs and revenues assumed for the 2002 test year. Dr. Rosenberg was the only witness to suggest changes to the data used in NSPI’s COSS. However, NSPI also made changes to the data used in its study. These were reflected in the “updated” COSS filed with Mr. Whalen’s letter of January 28, 2002.

7.2.3 Findings

[277] The Board reaffirms the findings in its Cost of Service Decision dated

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September 22, 1995. NSPI’s use of the Board’s approved methodology is accepted. Accordingly, for the purposes of setting rates, the Board will rely upon a COSS which begins with the study originally filed by NSPI, and reflects only the changes required to make the resulting study consistent with the findings made elsewhere in this decision. Such a study will ensure that the rates set reflect the Board’s decisions on key issues such as fuel costs. As part of the Compliance Filing, NSPI is directed to provide a COSS in the same format and detail as that provided in Appendix 2 of NSPI ’s original filing. With that study, NSPI is required to submit a brief statement identifying each change made from the original study, and explain how each change was required by, and conforms to, this decision.

7.3 Revenue/Cost Ratios and Rate Shock

7.3.1 Submissions - NSPI

[278] In its direct evidence, NSPI indicated that the following considerations can influence rate design:

(a) The principles of fairness, understandability, ease of administration, etc. (b) Customer impacts that are created in moving from existing rates to new rates (c) Price signals that are sent to customers (Exhibit N-1, p. 53)

[279] NSPI stated that its proposed rates attempt to balance these considerations and that all revenue/cost (R/C) ratios were adjusted to conform to the 0.95 - 1.05 range effectively ordered by the Board in its 1996 rate decision. Rate shock is not specifically alluded to in the above considerations.

[280] While the proposed rate increase averages 8.9% across all rate classes, some customers will experience considerably higher increases. NSPI describes the impact of the increases

Document : 78377 111 on customer strata as follows:

The increases [in the Residential and Small General classes] were limited such that no customer stratum experiences increases greater than 175% of the class average or no less than 25% of the class average. Energy charges were adjusted to recover the remaining revenue requirement. In the remaining classes, the energy charges were set to be no lower than the average marginal cost of energy in the test year, and demand and first block energy charges were adjusted to recover the remaining revenue requirement. Increases to individual customer stratum were limited to 50% to 150% of the class average. (Exhibit N-1, p. 54)

7.3.2 Submissions - Intervenors

[281] Dr. Rosenberg urged the Board to temper its application of the 95% to 105% range in order to avoid rate shock:

While the Company did bring revenue-to-cost ratios within the 95% to 105% bandwidth as Board guidelines suggest, they violated another regulatory principle that, in my opinion, ought to be complied with. I am referring to the principle of rate moderation or gradualism so as to ameliorate "rate shock". (Ex. N-113, P.58)

[282] He suggested that rate shock can be avoided by ensuring that no customer class increase (including customers on annually adjusted rates) exceed 10 percent "on an annual basis".

[283] Dr. Rosenberg’s testimony included the following:

Q. Dr. Rosenberg, how would [you] define rate shock? A. I think you have to put that in the context of the inflation rate. You know, if you had inflation at 7 to 8 percent, then, you know, rate shock might be 15 or 20 percent, but if you have inflation going at 2 to 3 percent, then in my view anything above 10 percent is rate shock. So, you have to do it in the context of what the general rate of inflation is.

Q. So, with respect to the application that's before us, would you -- how would you characterize the proposed rates vis-a-vis whether or not there's rate shock? A. I think by the tenor of some of the comments that you've received, I think a lot of people will consider it rate shock.

Q. And is that one of the reasons that you have proposed a cap on the rate of increase -- on the increases? A. That is correct. ( Transcript, May 24/02, p. 3643)

[284] Dr. Stutz defined rate shock in answer to questions from the Board as "a large

Document : 78377 112 increase in rates over a short period of time". He went on to say that rate shock must be related to the underlying rate increase. He also expressed the opinion that rate shock refers to the above-the- line rates and not to the formula rates such as the annually adjusted rates. He said that customers on the formula driven rates are pursuing a benefit and, as such, are bound by the formula. Dr. Stutz noted that adherence to the R/C ratio range of .95 to 1.05 can conflict with the application of any sort of rule pertaining to rate shock:

Q. I see what you’re saying, yes. It’s too narrow a spread. A. Yes. Q. Yes. Now, if you were to limit it to a percentage increase, can you adopt that -- or adapt that increase so that it would apply to all the customers in the classes or do you have to -- I guess my question is can you do that. A. It's very hard, particularly if you're pursuing other goals. But can you articulate a rule? I think I just did. So if the increase is 8.3 and we're limiting it to 150 percent, then we're going to limit it to 12.5 on a class and if we're limiting it to 200 percent for customers, we're going to limit it to 16.6 per customer. It's easy to write down numbers. There are two problems. One problem is that you have other goals and, in particular, you'd like to move into that 95 to 105 band width, which is also perfectly reasonable, also expresses equity in a certain sense. So you don't want to completely give that up and there's probably a conflict there. The other thing is that within rate classes customers differ widely, particularly in rate classes that have demand charges. Just based on load factor you can get all kinds of results. It's probably very hard to get as narrow a spread as I've described intra-class without changing the rate design significantly. And I haven't tried to do that, but I suspect it's going to be a problem. Like I say, my own slightly canned way of handling it is just to increase the kW and kWh charges proportionately. That'll limit those intra-class effects. (Transcript, June 4/02, p. 4019)

[285] Unlike Dr. Rosenberg, who described rate shock as an increase of over 10%,

Dr. Stutz described it in relation to the average, utility-wide increase. He submitted that increases of

150% of the average for class revenue requirements and of over 200% of the average for individual customers would be indicators of rate shock. However, he noted that these percentages need to be considered in light of the size of the average increase. The lower the average increase, the higher the increases in class revenue requirement might be before rate shock occurs. He addressed this point in the following extract from his testimony at the hearing:

A. ... rate shock is usually thought of in the context of a rate case of the type we're in

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now, and operationally, the way it gets thought about is to think about the level of increase and the ranges that customer classes or individual customers might see. So if there was a -- if you think of it in sort of an indexed way or a percentage way, if the increase is a hundred, then you would want to limit the rate classes, say, to increases of between 50 and 150. So in other words, you link the rate increase for the classes or bracket the rate increase for the classes based on how big the increase is for the company as a whole. Similarly, for customers, you might go out another 50 points. You might say, okay, if the individual rate class sees 150, an individual customer at the extreme might see 200. Now, the numbers are a matter of judgement, but the basic idea that it's related to the underlying rate increase is essential. It makes no sense to talk about a level of rate shock in the absolute sense. Is five percent a shocking increase? Well, it is if everybody's getting a 10-percent decrease and you're the one getting a five-percent increase. It's shocking. Why were you singled out? (Transcript, June 4, 2002, pp. 4015 - 4016)

7.3.3 Findings

[286] For over 15 years, the Board has indicated that customer class R/C ratios should be in the range of 95% to 105%. Dr. Rosenberg and Dr. Stutz were the only two witnesses to address the R/C ratios. Both generally supported the 95% to 105% range adopted historically by the

Board. Based on the evidence in this proceeding, the Board affirms its long-standing use of the 95% to 105% range for R/C ratios. While the Board affirms the commitment in its decision in NSPI’s last rate case to limit the class revenue requirements so that no class has an R/C ratio of below 95% or above 105%, it also believes that, depending on the scale of a proposed rate increase, there may be justification for the Board to exercise some flexibility in the application of this general rule.

Judgement must be exercised in balancing the R/C ratio objective with the desire to avoid rate shock.

[287] The Board finds that, to be reasonably applicable in a range of circumstances, the notion of rate shock must take into account the underlying average level of increase. Thus, in considering rate shock in this proceeding, the Board will rely on the approach proposed by Dr. Stutz.

Generally speaking, in considering the issue of rate shock, the Board will continue to strive towards its stated objective of keeping R/C ratios in the 95% to 105% range, subject to the foregoing caveat.

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The Board will apply these principles in its review of NSPI’s Compliance Filing.

7.4 Annually Adjusted Rates

7.4.1 Submission - NSPI

[288] The Annually Adjusted Rates (AARs) are described on pages 50 to 52 of

NSPI’s evidence (Exhibit N-1). NSPI explained that it has five rates that are adjusted on an annual basis, based on methodologies approved by the Board: the Generation Replacement and Load

Following (GRLF) rate; the Industrial Expansion Interruptible rate; and the three Real Time Pricing

(RTP) rates. In addition, the Mersey System rate is also determined annually on the basis of a formula approved by the Board.

[289] Revenues and costs associated with all of these rates are treated as “below-the- line” items in the COSS. Revenue requirements that are offset by revenues from the annually adjusted rates are deducted from total revenue requirements and only the remaining revenue requirements are allocated to the “above the line” rate classes, using the cost of service methodology.

NSPI submitted proposals for the AARs and the Mersey rate for 2002 as part of its original evidence. A revised proposal for each of the AARs for 2002 was submitted to the Board in conjunction with the updated financial forecast of January 28, 2002.

7.4.2 Submissions - Intervenors

[290] Drs. Rosenberg and Stutz were the only witnesses to address the AARs. Dr.

Rosenberg proposed a number of specific changes in the methodology and data used by NSPI to develop the AARs proposed for 2002. Dr. Stutz took a different approach. He discussed a number

Document : 78377 115 of general concerns, but not specific points of data and methodology. In its post-hearing brief, NSPI chose to respond to Dr. Rosenberg, but not Dr. Stutz.

7.4.3 Findings

[291] In addressing the AARs, the Board will deal separately with the methodology and data. Turning first to methodology, it is important to note that no witness, including Dr.

Rosenberg, claimed that NSPI applied the “formulas”, which define the charges included in the

AARs, in a fashion significantly different from, or inconsistent with, the application of those formulas approved by the Board in the past. In this proceeding, the Board directs that AARs for

2002 be developed using the formulas approved in the past. Changes in the formulas for the AARs will be discussed in a separate proceeding.

[292] Turning to the issue of data, the Board takes the same position it took with respect to the COSS. Development of the AARs for 2002 should begin with the data used in preparing the AARs included in NSPI’s initial evidence. However, that data should be modified to take into account all of the changes required elsewhere in this decision. Similar changes, as required, should be made to the Mersey rate.

[293] As with the COSS, NSPI shall submit compliance versions of the AARs and the Mersey rate for Board review. The Compliance Filing shall include a statement, identifying each data change made for each rate, as well as a brief explanation of how each change conforms with the findings and directives made in this decision. The revised AARs will be implemented after the

Compliance Filing has been reviewed by the Board, the changes, if any, required by the Board have

Document : 78377 116

been made, and the Board has issued a final Order approving the new rates. Once approved,

however, the new rates will be effective as at January 1, 2002.

7.5 Rate Design

7.5.1 Submissions - NSPI

[294] On pages 52 to 62 of Exhibit N-1, NSPI addresses its proposed designs for the

Interruptible Credit and the rates for Domestic, General, Industrial, Municipal and Unmetered

service. The proposed new rates are set out in Appendix 3 of NSPI’s application. There was no

change in those rate designs due to the revised data and COSS that accompanied Mr. Whalen’s letter

of January 28, 2002. As shown in Table A attached to Mr. Whalen’s letter, NSPI in fact proposed class revenue requirements that resulted in R/C ratios in the 95% to 105% range. However, as shown in Exhibit N-1, Table 6.1, NSPI’s proposed class revenue requirements in some cases exceed

150% of the average increase. In addition, as shown in Exhibit N-1, Table 6.2, the proposed increases applicable to individual customers with low energy consumption often far exceed 200% of the average increase.

7.5.2 Submissions - Intervenors

[295] Drs. Rosenberg and Stutz offered evidence concerning NSPI’s rate design.

MEUNSC also made a number of submissions with respect to rate design. The range of issues

addressed, particularly by Drs. Rosenberg and Stutz, and the breadth of opinion offered on specific

issues, is quite wide. The size of the Interruptible Credit is a specific example. NSPI, at page 50 of

Document : 78377 117 its evidence, suggests a credit of $3.08 per kVA. Dr. Rosenberg calls for an increase to no less than

$4.00 (N-117, page 20). At page 66 of his evidence, Dr. Rosenberg argues that, if one uses “more realistic” assumptions than those selected by NSPI, a figure of $7.33 per kW could be justified. On the other hand, at pages 28 to 30 of his evidence, Dr. Stutz cites a number of factors which together suggest that a credit less than $3.08 may be justified. In light of the breadth of the issues raised, as well as the extent of the disagreements on specific items, it appears that a separate rate design hearing is appropriate.

7.5.3 Findings

[296] The Board has determined that it will not address the rate design issues raised at this time. Instead, it will simply require a rate design which furthers the Board’s goal of having

R/C ratios in the 95% to 105% range, and which minimizes rate shock to the extent possible in accordance with the Board’s earlier comments. The rate design issues not addressed in this decision will be the subject of a separate, subsequent rate design proceeding.

[297] The Board finds that, for purposes of setting rates in this proceeding, the general rate design approach described on pages 53 and 54 of NSPI’s evidence should be followed.

NSPI’s procedures (a), (b) and (c) provide a general methodology for setting class revenue requirements. They are as follows:

a) All revenue/cost ratios were adjusted to conform to the 0.95 - 1.05 range ordered by the Board. b) Any revenue deficiencies resulting from a) were allocated to those classes that had the lowest R/C ratios. However, Large Industrials who were already receiving the largest price increases, were held at 0.95. c) The revenue increases or decreases resulting from a) and b) were added to the average increase required to allow NSPI to meet its proposed revenue requirement, to calculate average increases required by class. (Exhibit N-1, p. 53)

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[298] Accordingly, NSPI is directed to set class revenue requirements following these general principles. In doing so, NSPI shall rely on the COSS to be developed and provided as part of the Compliance Filing as specified in this decision and the existing Interruptible Credit of

$3.43 per kVA per month.

[299] Application of the above principles involves some judgment. In exercising that judgment, NSPI shall, to the extent possible, limit increases to 150% of the average increase in revenues required from the existing rates as a whole given the revenue requirement allowed in this decision. The Board also notes that rates should be developed on the basis that the transformer credit and the interruptible credit remain at the present approved levels.

[300] In order to create the specific rates required for each class, NSPI shall increase all the rate components currently applicable to each class by the percentage increase in the revenue requirement for that class. This “across-the-board” rate design procedure is similar, but broader in scope than that recommended by Dr. Stutz. By broadening Dr. Stutz’ procedure, the Board removes, as fully as possible, any differences between changes in class revenue requirements and customer bill impacts. This should avoid the dramatic variation in bill increases shown in NSPI’s Table 6.2 noted above.

[301] The Board directs NSPI to develop and submit, as part of its Compliance

Filing, rates which meet all of the requirements described above to the fullest extent possible. As part of the Compliance Filing, NSPI should, at a minimum, provide the following:

· a set of revised rate sheets similar to those in Appendix 3 of the filing,

showing proposed charges;

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· a table similar to Table 3.6 in its application, showing revenues under current

and proposed rates;

· a table similar to Table 6.1 in the application, showing changes in class

revenues;

· a table showing R/C ratios by class before and after the increases;

· a table similar to Exhibit 10 in Appendix 2 to the application supporting the

“before” and “after” R/C ratios;

· a table similar to that provided in response to SEB-IR-125, showing a proof

of revenue.

These tables shall be accompanied by a statement explaining how NSPI applied principles

(a), (b), and (c), taking into account the requirement to avoid increases over 150%.

[302] The Board approves NSPI’s request to delete the following two expired rates:

· Time of Day Expansion Interruptible Rate; and · Surplus Power Interruptible Rate (Exhibit N-1, pp.51-52)

7.6 Future Rate Design Proceeding

7.6.1 Board Directives

[303] In light of the large number of issues raised concerning the AARs, the

Interruptible Credit and the other rates, the Board has decided to conduct a separate rate design proceeding, to be held in 2003. The "ground rules" for the proceeding will include the following:

· The current Cost of Service methodology will be accepted and NSPI’s COSS

model will be used. Data inputs can be adjusted, but not methodology.

· Each party proposing rate design changes for the existing rates will submit

two Summary Exhibits, similar to Exhibit N-152, JS-10 which was filed in this

Document : 78377 120

proceeding by Dr. Stutz, showing the specific charges proposed compared to

the charges approved in this proceeding. One exhibit will be based on

NSPI’s current class revenue requirements, the other on the party’s preferred

class revenue targets.

· NSPI will provide standard billing determinants, similar to those in SEB-IR-

125. Each party will use those determinants to show the revenues produced

by the rates presented in the Summary Exhibit.

[304] Similar ground rules will be developed to govern the examination of the

AARs.

[305] Within the framework established by the ground rules, the parties will have the opportunity to propose changes in rate design, including those proposed by Drs. Rosenberg, Stutz and MEUNSC in this proceeding. In order to minimize effort, parties will be allowed to enter testimony, exhibits and responses to information requests from the present proceeding into evidence in the rate design proceeding.

7.7 Municipal/Large Industrial Rate Relationship

[307] For the first time in more than 25 years NSPI has proposed in this application to "decouple" the Municipal rate from the Large Industrial rate. Over this considerable period of time, the demand and energy charges in the Municipal rate have always been the same as the demand and energy charges in the Large Industrial rate. NSPI now proposes to increase the demand charge in the Municipal rate to $9.81 per month per kilovolt ampere of maximum demand and to increase the demand charge in the Large Industrial rate to $9.35. The energy charge in the Municipal

Document : 78377 121 rate would increase to 4.70 cents per kilowatt hour compared to a proposed Large Industrial energy charge of 4.64 cents per kilowatt hour.

[308] The Board has considered the arguments put forward by NSPI in favour of making this change and the arguments by MEUNSC in favour of retaining the status quo. The Board is not persuaded that the arguments in favour of decoupling the rate are so compelling that any change in the longstanding practice needs to be made in advance of the rate design proceeding to be held pursuant to this decision. Accordingly, the Board directs that NSPI, in revising its rates in accordance with the directions set out above, shall maintain the Municipal and Large Industrial rate components at the same levels.

7.8 Green Rider Rate

7.8.1 Submission - NSPI

[309] By letter dated December 12, 2001, NSPI requested interim Board approval for a new rate which, it states, will allow:

... customers who are so inclined to voluntarily contribute $5.00 per month in support of NSPI’s efforts to develop green energy supplies in Nova Scotia. In return for each $5.00 subscription, NSPI will commit to producing or purchasing 125kWh per month from green sources, thus displacing fossil fuels. The proposed contribution of $5.00 to support 125kWh is equivalent to a contribution of 4 cents per kWh. (NSPI letter dated December 12, 2001)

[310] NSPI’s proposal involves the establishment of a voluntary rate under which customers could pay a premium for electric service, in $5 increments, to promote the use of electricity generated from environmentally-friendly renewable sources such as wind power. NSPI states that the premium is designed to cover the incremental cost of providing power and energy from "green sources" and was developed on the basis of the cost of two wind turbines. NSPI has

Document : 78377 122

already canvassed the acceptability of the concept with certain customers, including the federal

government, and is satisfied that some customers will pay a premium to promote electricity

generated from green sources.

[311] The Board determined that the green rider rate should form part of the general

rate hearing and deferred consideration of the rate until that time.

7.8.2 Submissions - Intervenors

[312] The Board received a number of submissions on the green rider rate from

intervenors, including the NDP and ECANS. ECANS, in particular, believes that aspects of NSPI’s

proposal would benefit from additional scrutiny. The NDP opposed the structure of the green rider

as presented, arguing that customers should not have to pay a premium to encourage the generation

of electricity from more environmentally-friendly sources.

7.8.3 Findings

[313] The Board appreciates the helpful suggestions of all the parties with respect to

this issue. The Board is cognizant of the fact that details of the proposed green rider rate were not

included in the notice of the rate application published by the Board. It agrees with ECANS that

parties ought to have an additional opportunity to review this rate. The Board is also aware that the lack of notice to the public of the proposed green rider rate was not as a result of any oversight on the part of NSPI. In order to balance the interests of both sides on this issue, the Board will not give

final approval of the green rider rate at this time. It will, however, approve the green rider rate on an

Document : 78377 123 interim basis to be reviewed in detail during the next general rate proceeding.

Document : 78377 124

8.0 RULES AND REGULATIONS

8.1 Submission - NSPI

[314] In its application, NSPI requested that the Board approve amendments to

NSPI’s Rules and Regulations to provide for: 1) a change in the requirement governing notification of disconnection; and 2) a change in the interest rate paid on deposits from 8% to the prevailing

Royal Bank of Canada lending rate less 1%. NSPI notes that, as at the time of filing, this would result in interest on deposits of approximately 3%. At present, the regulations are as follows:

6.2 MANNER OF DISCONNECTION Prior to the proposed date of disconnection the Company shall make reasonable efforts to contact the customer, to determine whether the customer has satisfied the outstanding account or is willing to make satisfactory arrangements to settle the outstanding account. If such contact is made and payment is not or has not been made and satisfactory arrangements for payment have not been made, the Company may disconnect the electric service. If such contact cannot be made the Company shall attempt to contact the customer or other responsible adult upon the premises served by the electric service account. If the Company is unable to contact such persons upon the premises, a written notice shall be left in a conspicuous location stating the date and time after which electric service will be disconnected unless the amount specified for the outstanding account is satisfied or satisfactory arrangements made to settle the outstanding account and thereafter the Company may disconnect the existing electric service.

7.1 SCHEDULE OF CHARGES

The following charges shall apply: (a) Connection or reconnection of electric service, .... (i) Interest on Deposits 8% per annum (simple interest)

[315] With respect to Regulation 6.2, NSPI wishes to add a provision, as an alternative to leaving a “doorknob” notice in circumstances where customers cannot be contacted, allowing customers to be notified by priority mail which requires a signature. The proposed regulation reads as follows:

B) MANNER OF DISCONNECTION

Document : 78377 125

Prior to the proposed date of disconnection the Company shall make reasonable efforts to contact the customer, to determine whether the customer has satisfied the outstanding account or is willing to make satisfactory arrangements to settle the outstanding account. If such contact is made and payment is not or has not been made and satisfactory arrangement for payment have not been made, the Company may disconnect the electric service. If such contact cannot be made the Company shall attempt to contact the customer or other responsible adult upon the premises served by the electric service account. If the Company is unable to contact such persons upon the premises, a written notice shall be left in a conspicuous location or the written notice shall be delivered by priority mail requiring signature. Either notice shall state the date and time after which electric service will be disconnected unless the amount, specified for the outstanding account is satisfied or satisfactory arrangement made to settle the outstanding account and thereafter the Company may disconnect the exiting electric service. (Exhibit N-1, Appendix 4, Reg. 6.2(b))

[316] With respect to the proposed change in the interest rate paid on deposits, NSPI indicates that the change will result in an:

Interest rate based on Royal Bank prime rate minus 1%; set January 1st of each year. (Exhibit N-1, Proposed Reg. 7.1(i))

8.2 Submissions - Intervenors

[317] No objections were noted to these requests.

8.3 Findings

[318] The Board approves the regulations as proposed.

Document : 78377 126

9.0 OTHER ISSUES

9.1 Regulatory Process - Timing

[319] There was comment on the record in this proceeding of NSPI’s desire for changes in the existing regulatory process. This is highlighted in the following exchange between

Board Counsel and Mr. Huskilson:

Q. Mr. Huskilson, just turn to page 6 of Mr. Mann's remarks, and at the -- the very first paragraph begins, "We are striving at all times to do better," since there's no page references on this. And the part of that page that I wanted to direct your attention to begins at the fourth paragraph from the bottom where it says: "However, we need more than strong management. We need timely rate action and a commitment to regulatory reform. At the moment, we are engaged in two very different regulatory proceedings here and in Maine. Our experience in Maine with negotiated performance-based rate making suggests that there may be better and more flexible and less divisive ways of establishing our prices. Instead of an expensive and lengthy hearing, we participated in a collaborative process for a defined 90-day period." And on the top of the next page, he says: "The successful conclusion of these negotiations with the regulator, the public advocate and key stakeholders has led to a recommendation for a six-year alternate rate plan being sent to the commissioners for their approval." Has that approval, by the way, been granted yet? A. I'm not aware of the answer to that, but I believe not. (Transcript, May 23/02, pp. 3206-3208)

[320] Under cross-examination by Counsel for Annapolis, Mr. Huskilson said:

Well, I think -- I mean, many people have asked the question as to why we are in -- why we're in the middle of the test year with this application. One of the reasons is the delay that's occurred. The other reason is that we were working very hard at the end of last year in trying to find ways of not having to come forward with an increase. But at the end of the day, the markets were such that we were unable to not have to do that. But we have traditionally worked hard to make that happen, and we continue to do that. (Transcript, April 23/02, pp. 286-287)

[321] Annapolis points out in its closing submission that:

NSPI has not demonstrated that it is entitled to the rates it seeks. A rate proceeding is intrinsically an asymmetrical affair; the utility possesses all the evidence relevant to its revenue requests and the intervenors possess nothing more than what the utility is inclined to provide to them or what the Board orders. It is unseemly for the utility to complain about the length and cost of such proceedings when its costs will all be recovered from the ratepayers and its inaccurate, unresponsive and misleading information (whether inadvertent or otherwise) has been a principal cause of the prolixity of the proceedings. The result and costs to the intervenors are by and large not recoverable and pose a test to their endurance and resolve.

Document : 78377 127

(Annapolis, Closing Submission, p.3)

[322] MEUNSC stated in its final brief that:

N.S.P.I. was aware by at least May of 2001 that coal prices were rising. This was dramatically confirmed by September 4, 2001. We hope that someone, in N.S.P.I. or Emera, whichever was then in charge of procurement, was doing market research in the interim. Mr. O’Neill stated under cross “Speaking from a financial point of view, if I had my way we would have been filing last August.” . . . N.S.P.I. has staff knowledgeable in rate design and regulatory affairs, indeed charged with those responsibilities and presumably accounting staff have the capacity to generate financials. They should have had an application prepared and ready to print, subject to updates. It is difficult to imagine why the company filed a rate case requesting large and controversial increases, using 2002 as the test year, on December 18, 2001. Unless having seen the “perfect storm” in coal prices, they sought the perfect window in presenting an application. At the time of their filing, CBDC was in fact closed and no operators were available. (See Medine, Confidential N-37, pages 9 and 10). CBDC coal at $2.11/mmbtu was not in the future equation. There was no contract with Nova, so no need to consider that price. The N.S.P.I. panel denies the connection, but absent some compelling motive, waiting until December 2001 to file was imprudent even if the coal procurement was not. (MEUNSC, Final Brief, p.26)

[323] The Province in its final submission states that:

NSPI’s general rate application was filed on December 18, 2001. After a lengthy pre-hearing discovery process, including a preliminary motion for production of documents, the hearing commenced on April 22, 2002 and finished on June 4, 2002. The Province submits that alternative procedures to the hearing process should be canvassed to determine if efficiencies can be gained in the process and if there is an appropriate mechanism for settling some of the regulatory issues outside of the costly hearing process. (Province, Final Submission, p.19)

[324] As noted earlier in this decision, the initial hearing on NSPI’s December 18,

2001 application was scheduled for March of 2002. It was only after the majority of intervenors requested an adjournment that the hearing was postponed until April 22, 2002. The Board believed at the time (and continues to be of the view) that the adjournment request was reasonable given the complexity of the material; the lengthy interval between rate cases; the scope of the issues; and the magnitude and potential impact of the proposed increases.

[325] The Board further notes Dr. Stutz’s comments on the process in Nova Scotia as compared to other North American regulatory jurisdictions:

Yes, my view is that you're doing pretty well with the methods you have. I think that there

Document : 78377 128

probably are administrative changes such as the conference I mentioned earlier which might make rate cases proceed more smoothly. But I don't believe that you need to make systemic changes. Performance based regulation would be one such systemic change that might be suggested. My feeling is that you have a very good form of performance based regulation built into your current arrangements. Normal test year regulation without a fuel adjustment clause is, in my view, a very effective form of performance based regulation. And, in fact, I think you have evidence that it works. If you look, the company stayed out for a long time, managed its costs, produced an acceptable rate of return, and was only forced in by a truly extraordinary change in its fuel prices. But that's precisely what performance based regulation is supposed to do. So I would recommend on that front you simply declare a victory. (Transcript, June 4/02, pp.3977-3978)

[326] The Board agrees with the comments made by MEUNSC that NSPI should

have anticipated that an application for such a significant increase would attract considerable

attention and scrutiny. It is inappropriate in the Board’s view, to suggest that opportunities for a

thorough scrutiny of NSPI’s case should be short-circuited in order to accommodate a compressed time frame of NSPI’s own making.

9.2 Disclosure

[327] A number of intervenors have suggested that a lack of timely disclosure on the part of NSPI resulted in a lengthier than necessary process. For example, SEB, in its reply argument, stated that:

Stora Enso/Bowater take exception with NSPI’s description at line 26 of page 4 of their Argument that there was an “extraordinary discovery process authorized by the Board in this case”. NSPI seems not to understand that it has been granted the privilege of a monopoly, and that the regulatory process is designed to ensure that monopoly power is not abused. Intervenors have every right to access information of the type sought by them in this proceeding. The record is clear that information of the type sought by Stora Enso/Bowater in this proceeding is normally available in other North American jurisdictions, and available without the intervenors having to go to the considerable time and expense expended in this Hearing to achieve access to that information. [See for example Transcript, pages 1774- 1775, questions 72-76 and Exhibit N-117, page 3, line 3] (SEB, Reply Argument, p.3)

[328] Annapolis, in its closing submission, also reiterates concerns with respect to disclosure:

Document : 78377 129

Ms. Medine was frustrated in her review as she explained in her report that “the information provided by NSPI through its filing, the IR responses and, and confidentially at its offices was disjointed and, at times, inaccurate and incomplete” (Exhibit N-37,p.1). These complaints were echoed by Ms. Sharon Hennings and Dr. Rosenberg, the experts retained on behalf of Stora/Bowater (Transcript, Hennings, P. 1671; Rosenberg, pp.3516-3517). (Annapolis, Closing Submission, P. 19)

[329] In Exhibit N-117, Dr. Rosenberg quoted the following excerpt from Mr.

Huskilson’s testimony:

(Huskilson) Mr. Cooper, in this province we have an open and transparent process where customers can review our information and ultimately the Board makes a decision based on that. We just want to be in a position where we are sharing the information with our customers and with the Board that we have, and we don’t want to be in a position where we’re withholding information. (Emphasis added)

[330] Dr. Rosenberg then continued as follows:

While those were admirable sentiments expressed by Mr. Huskilson, in my view there was a serious gulf between this aspiration and the actual process. It was frustratingly difficult to extract even what I would consider to be the most elemental amount of data and documents during the discovery phase in this case. For example, in the first round of discovery, Stora Enso/Bowater could not get access to: - The cost date for export sales; - Full details supporting the fuel cost data in Table 3.8: - Fuel cost contracts; - The model used to develop the Company cost of service study; - Input and Output of Production cost simulation models: - Certain class load shapes; - Details of cost allocations to below the line classes; - Workpapers supporting many calculations. In fact, despite the voluminous responses to the first round of discovery, Stora Enso/Bowater did not receive a single computer spreadsheet in electronic format. In this day and age, when computer spreadsheet models are indispensable in preparing a rate application, this is inexcusable. Moreover, it is not at all the practice followed by applicants in regulatory proceedings in the vast majority of states and provinces with which I have had experience. Eventually we did gain access to some of that data, and to some spread sheets in electronic form. However, other items were never disclosed, or disclosed in such a fashion that it made independent analysis and corroboration tedious and time consuming.

Document : 78377 130

The rate hearing procedure is of necessity, and by design, an adversarial process. It is only by parties with different interests and constituencies presenting alternative viewpoints that the regulator can arrive at an informed decision. In fact, in Alberta, the Board so values these different opinions that participant[s] often get a significant portion of their costs back, depending upon the contribution to the hearing process that the Board perceives. But this adversarial process can only function efficaciously when there is in fact an “open and transparent” flow of information. Now I appreciate the commercial sensitivity of some of this information. Nevertheless, there are ways to give parties with legitimate interests sufficient access to models, documents and workpapers, while still providing NSPI with adequate safeguards for its concerns. I urge the Board to facilitate the discovery process in the future - in other words to make NSPI practice the “openness and transparency” it preaches. For this hearing, my recommendation is that the Board take notice of this unnecessary problem when weighing the evidence. (Exhibit N-117, pp.2-3)

9.3 Process Improvements

[331] The Board is in favour of implementing techniques which could improve the efficiency of proceedings. Dr. Stutz, in response to Board questions concerning possible improvements stated that:

. . . One thing would be simply to make it clear that having the intervenors understand these things at the level -- at whatever level the Board believes is appropriate, whether it's the almost audit level one would say of the coal witnesses, or whether it's at a higher level, but whatever level is appropriate to make it clear that the requirement for having a successful rate case is that you make that information easily available. That would be a help, because then the company would, of course, understand what it needs to do, and I presume would try to do it. Let me say I personally didn't feel frustrated in obtaining information from the company, but I did not attempt to perform the audit level review that Ms. Medine and others may have tried to perform. A second thing that could be done would be to have some sort of a conference between the first set of IR’s and the second, and the purpose of these conferences is simply to provide technical information quickly and easily. This is done routinely in other jurisdictions. I don't know what constraints there may be on doing it here. (Transcript, June 4/02, pp. 3973-3974)

[332] The Board does not agree with NSPI’s position that it was subjected to an “. .

. extraordinary ‘discovery’ process authorized by the Board in this case”. The Board believes that

Document : 78377 131 the intervenors were entitled to examine and challenge NSPI on these issues and they could not fairly do so without the data that was sought. NSPI is a monopoly utility whose revenue requirement must be subject to thorough public scrutiny. It is NSPI, not the intervenors, which bears the burden of proof in establishing that a rate increase is warranted.

[333] NSPI has pointed out during this proceeding that circumstances have changed since the last rate filing in 1995 - i.e., competitive pressures, foreign exchange, increased costs, environmental considerations, etc. Ironically, it is clear from the many submissions received by the

Board that the intervenors in this proceeding face many of these same pressures. Many argue that they, unlike NSPI, operate in a truly competitive environment. Based on the application as filed, some were facing rate increases in excess of 25%. It should not be surprising that NSPI has been confronted by ratepayers who demand to be thoroughly informed and who challenge NSPI in terms of the efficiency and competency of its operation and the validity and reasonableness of its proposed rates. The Board does not expect this trend to diminish over time.

[334] Accordingly, the Board will facilitate a technical conference, in advance of the next hearing, between NSPI and intervenors for the purpose of streamlining the information request and response process. The Board hopes that this will result in a shorter hearing and less acrimony between the parties. This conference will occur following the filing of NSPI’s application and prior to the issuing of IRs.

[335] Further, the Board notes that it does not object in principle to a settlement process in advance of the hearing provided that all classes of ratepayers are represented in these discussions. To this end, should NSPI wish to pursue a settlement process with intervenors, the

Board will appoint a consultant, at NSPI’s expense, to act as a consumer advocate for otherwise

Document : 78377 132 under-represented groups of customers (i.e., domestic, small commercial). The Board may also determine that it would be in the public interest to ensure that these customers are represented by a consumer advocate at the technical conference referred to above. It goes without saying, of course, that any settlement agreement reached by the parties would be subject to scrutiny at a public hearing by the Board.

9.4 Dalhousie Legal Aid Service

[336] In a well-documented and carefully argued submission to the Board,

Dalhousie Legal Aid Service (DLAS) addressed the effect of electric rate increases on low income residential customers. Drawing upon a comparison of electricity rates in North American cities undertaken by Hydro Quebec, and based on a monthly consumption of 1,000 kWh, DLAS points out that of the Canadian cities surveyed, residents of Halifax pay the third highest residential rates in

Canada.

[337] DLAS states that the application as filed would result in disproportionate rate increases for residential customers who use very little electricity. NSPI indicated in its direct evidence that customers using less than 2,000 kWh per year would face a 15.3% increase in their bills compared to the average proposed increase of 8.9%. DLAS notes, however, that low income customers are not always low users of electricity.

[338] DLAS states that Nova Scotians in receipt of social assistance spend 10.8% of their incomes on electricity compared to 5% for the consumer of average income. If the rate application were to be granted in full, Nova Scotian recipients of social assistance would apply

12.2% of their incomes to the purchase of electricity, which would represent the highest such

Document : 78377 133 proportion in Canada.

[339] DLAS goes on to point out that since 1995, the year before the Board last authorized NSPI to increase its rates, power increases have not resulted in corresponding increases in shelter benefits to low income consumers. Nova Scotia “total annual welfare incomes”, measured on the basis of the maximum shelter rates available, have in fact declined from $12,271 in 1995 to

$12,250 in 2001. DLAS further states that there has been a “dramatic” increase in the number of service disconnections and use of security deposits since 1996.

[340] DLAS’ principal recommendation to the Board is that it introduce a “rate subsidy program” under which low income residential customers would be subsidized by other customers of the utility. DLAS does not explain how such a program should be implemented.

[341] The Board has in the past rejected the principle of rate subsidies based on income disparity. For example, in its 1992 decision on a rate application by NSPI, the Board said this:

It was suggested that the Corporation be required to report on the affordability of domestic rates for seniors, people with disabilities and other individuals or families who are living on a fixed income. Changes to rate structures to provide subsidized rates to such persons would be discriminatory and thus contrary to the basic thrust of regulation, which is to ensure customers pay rates that are justified by the cost of serving them. The government might be interested in such a study from the social assistance viewpoint, but it is not within the regulatory mandate.

Section 67(1) of the Act is pertinent to any discussion of rate subsidies:

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.

[342] The Board recognizes DLAS’ argument that, in the context of human rights legislation, the courts might well hold that differences in treatment based on differences in income level might be justified as being differences in circumstances and would not constitute

Document : 78377 134 discrimination. The Board has given renewed consideration to the issue of rate subsidization based on income in light of the arguments put forward by DLAS. However, it continues to hold the view that the implementation of such rate subsidy programs is neither contemplated by s. 67(1) nor appropriate in the context of the regulation of public utilities.

[343] The Board would note that the reduction in the revenue requirement ordered in this decision and the Board’s direction that the components of the domestic and other rates shall increase by the same percentage will alleviate the disproportionate effect of NSPI’s proposed rate increase on residential customers who consume low amounts of electricity.

10.0 SUMMARY OF DISALLOWANCES AND ADJUSTMENTS

[344] NSPI, in its direct evidence, submitted that an additional $67.1 million was required from “above-the-line” customers (i.e., not LRR, GRLF or IE customers). This is illustrated in the following table.

Table 6.1 Changes in Class Revenues (millions of dollars)

ABOVE-THE-LINE-CLASSES REVENUE UNDER ADDITIONAL REVENUE PROPOSED % INCREASE CURRENT RATES REQUIRED REVENUE

Residential Residential non ETS $363.0 $32.3 $395.3 8.9% Residential ETS $4.7 $0.4 $5.1 8.9% Total Residential $367.6 $32.7 $400.4 8.9%

Commercial Small General $8.9 $0.8 $9.7 8.8% General Demand $206.0 $10.3 $216.3 5.0% Large General $23 $3.8 $27 16.2% Total Commercial $238 $15 $253 6.2%

Residential & Commercial $605.8 $47.6 $653.4 7.9%

Industrial Small Industrial $16.9 $1.6 $18.5 9.2% Medium Industrial $34.9 $4.4 $39.3 12.5%

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Large Industrial $71.8 $11.8 $83.6 16.4% Total Industrial $123.6 $17.7 $141.3 14.3%

Other before Export Sales Municipal $11.1 $1.8 $12.9 16.4% Unmetered $18.5 $0.0 $18.5 0.0% Other before Export Sales $29.6 $1.8 $31.4 6.1%

Total Above-the-line Classes $759.0 $67.1 $826.1 8.9%

BELOW-THE-LINE CLASSES Other Electric Revenue $0.0 $0.0 $0.0 0.0% Gen. Repl. & Load Follow $17.8 $0.7 $18.5 3.9% Bowater Mersey $6.7 $0.0 $6.7 0.0% Industrial Exp. (Stora) $54.7 $2.5 $57.2 4.6% RTP $9.1 $0.3 $9.4 3.3% Total Below-the-line Classes $88.3 $3.5 $91.9 4.1%

In-Province Total $847.3 $70.6 $918.0 8.3% (Exhibit N-1, Table 6.1)

[345] For the reasons given in the preceding sections of this decision NSPI’s proposed revenue requirement has been reduced as set out in the following table:

Test Year Expenses Reductions to NSPI’s Requested Revenue Requirement

ITEM AMOUNT OF REDUCTION

10% Imported Coal cost adjustment $19,700,000

Disallowed CBDC buyout $ 2,700,000

Disallowed Compensation - Executive $ 303,500

Disallowed Compensation - Incentive $ 1,580,000

Reduced Other expenses (Sponsorship & Donations) $ 635,800

Reduced Return on Equity (based on R.O.E. of 10.15%) $ 8,500,000

Reduced Capital Structure $ 3,300,000

Coal Transportation Costs $ 2,000,000

Emera Energy Agency Fee $ 672,000

Adjusted Additional Hydro generation $ 3,000,000

Total disallowances and adjustments $42,391,300

[346] The Board notes that the reductions shown in the Table above are estimates based on the information available to it. The actual amount of the reduction may change somewhat

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and will be reflected in NSPI’s Compliance Filing. In particular, NSPI must verify in its Compliance

Filing the reductions in the revenue requirement due to decreasing the Common Equity component

from 40% to 35% and decreasing the Return on Equity from 11% to 10.15%.

[347] The additional revenue requirement of $67.1 million requested by NSPI in its

application resulted in an overall rate increase of 8.9%. The reductions in the revenue requirement of

$42.4 million set out above, reduce the overall rate increase from 8.9% to 3.3%.

11.0 SUMMARY OF BOARD FINDINGS

11.1 Revenue Requirement/Rate Increase

[348] NSPI, in its application to the Board, requested an increase in its revenue

requirement from general rates of $67.1 million for the test year 2002. Such an increase, according

to NSPI, would result in an average rate increase of 8.9% in general rates across all customer classes,

with some customers experiencing considerably higher increases. The Board, after reviewing NSPI’s

projections, has reduced the revenue requirement by $42.4 million (see Table on page 146). This

results in a reduction in the average rate increase across all classes from NSPI’s proposed 8.9% to

3.3%.

11.2 Capital Structure

[349] NSPI requested Board approval to increase the common equity component of

its capital structure from 35% to 40% for the test year with the ability to increase this to 45% over

time.

[350] The Board finds that there is insufficient justification to increase the common

equity component from its present level of 35% to 40% at this time. The Board believes that without

a corresponding increase in the common equity ratio of NSPI’s parent company, Emera, there will

Document : 78377 137 likely be no overall benefit accruing from an increase in the common equity level of NSPI.

[351] The Board directs that the common equity level of NSPI remain at 35% for rate-making purposes, but has no objection to NSPI increasing its actual equity ratio to 40% in the future. However, at any subsequent rate hearing, the Board will determine what equity ratio is appropriate for rate-making purposes. This finding reduces NSPI’s revenue requirement by

$3,300,000.

11.3 Rate of Return on Equity

[352] NSPI requested approval of rates which would result in a return on common equity of 11.0%. It further requested approval of an allowed earnings range on common equity of

11.0% to 12.0%. Rates were last set in 1996 on the basis of a return on common equity of 10.75% with an allowed range of 10.5% to 11.0%. The Board believes that the rate of return on equity should be set at a rate which fairly reflects the risk associated with an investment in NSPI. The Board considers that a rate of return of 10.15% most fairly reflects this risk. Accordingly, the Board fixes the rate of return on common equity at 10.15%. The Board continues to consider that it is useful to establish an earnings range, which it sets at 9.90% to 10.40%. As a result, NSPI’s revenue requirement is reduced by $8,500,000.

11.4 January Adjustment

[353] The Board considers that the data filed by NSPI with its original application on December 18, 2001 represented the Utility’s best forward-looking estimate of the 2002 test year.

The Board determined that NSPI’s January 28, 2002 letter, which updated the December 18, 2001 filing, should be disregarded. The Board believes that incorporating actual data with test year

Document : 78377 138

projections may have the effect of lessening the consistency and reliability of the test year data.

11.5 Coal Costs

[354] The Board finds that NSPI’s estimated fuel costs for the 2002 test year are

based on higher than normal coal costs and, consequently, are not suitable for rate-making purposes.

Accordingly, the Board finds that the cost of fuel for the test year must be reduced in order to ensure that the costs are more representative of the period during which the rates will be in place (i.e., late

2002 and into 2003). The Board finds that to normalize these coal costs on a go-forward basis for the remainder of this year and into 2003, a 10% reduction in test year costs for imported coal is reasonable. This will result in a reduction of approximately $19.7 million in the revenue requirement.

11.6 CBDC Buyout

[355] In April of 2001, NSPI entered into an amending agreement with CBDC which resulted in the early termination of a long term coal supply contract. The effective date of the amending agreement was January 1, 2000. The cost of the contract buy-out was $13.4 million.

NSPI requested Board approval to include this cost ($2.7 million per year for five years beginning in

2002) as an expense to be borne by ratepayers.

[356] The Board finds it difficult to discern a future benefit to ratepayers as a result of a fee paid to terminate a coal supply contract approximately one month before the announcement was made that coal mining by CBDC would cease. The Board finds that, based on the evidence, it is reasonable to conclude that the benefits of the $13.4 million paid to terminate the CBDC coal supply contract have already been realized by shareholders. Under these circumstances, the Board finds that it is not appropriate to transfer the burden of this fee to the ratepayers and, accordingly, the expenses

Document : 78377 139 associated with this fee are disallowed and test year expenses are reduced by $2.7 million.

11.7 Hydro Generation

[357] NSPI, using five year average rainfall data, projected a reduction in hydro generation over previous years. Since there is little or no fuel required in hydraulic generation, a decrease in this cheaper form of power production results in higher fuel costs. It is reasonable, in the

Board’s opinion, to use a twenty-three year average for hydro generation rather than a five year average. Using NSPI’s calculations, the Board finds NSPI’s avoided fuel cost as a result of increased hydro generation to be $3 million. NSPI’s test year expenses will be reduced accordingly.

11.8 Executive Compensation

[358] The Board is concerned about the rapidly increasing compensation which is being paid to the executive management of NSPI and which is included in costs to be recovered from ratepayers. It is clear that the compensation costs for NSPI’s two most senior executives have increased dramatically over the past several years. The Board does not believe current compensation levels are acceptable to the vast majority of ratepayers in this Province. The Board is of the view that it is appropriate for the shareholders to bear a significant portion of the increased compensation costs. The Board believes it is fair for ratepayers to bear compensation costs that have increased at a reasonable rate from those paid at the time of the last rate hearing.

[359] With respect to the compensation paid to Mr. Huskilson, NSPI’s Chief

Operating Officer, while the Board has some concerns about the magnitude of the amount ($335,769

Document : 78377 140 in salary and $147,900 in bonuses in 2001), as well as the significant increase during the last few years, the Board is prepared to accept it as a reasonable reflection of his contribution to NSPI subject to reductions in incentive compensation and corporate support allocation reductions.

[360] With respect to the compensation paid to Mr. Mann, President of NSPI, the

Board has no evidence before it of Mr. Mann’s duties with NSPI and, consequently, there is scant support for charging to ratepayers a 73% allocation of his $832,000 annual compensation package.

The Board is left with the impression that much of Mr. Mann’s time is spent on activities of Emera, and its 42 affiliates. Accordingly, in the absence of any evidence to the contrary, the Board disallows one-half of the cost of Mr. Mann’s compensation which has been included in NSPI’s revenue requirement. This represents a disallowance of $303,500.

11.9 Incentive Compensation

[361] NSPI requested that the Board approve 100% of incentive compensation

(bonuses) as a charge against ratepayers. The Board has heard no evidence which persuades it that ratepayers should bear 100% of the cost of incentive compensation. The Board believes that both shareholders and ratepayers benefit from a well run-utility. The Board reaffirms its earlier decision that an equal division of incentive compensation is the most appropriate method of allocating this cost. Accordingly, NSPI’s 2002 test year expenses are reduced by approximately $1.58 million.

11.10 Operating, Maintenance and General Expenses

[362] The Board believes that it is incumbent on NSPI management to be able to

Document : 78377 141 demonstrate that it has made every effort to operate on a cost efficient basis when it seeks to increase electric rates in Nova Scotia. The Board is not satisfied that NSPI management has made every reasonable effort to eliminate unnecessary expenses.

[363] The Board’s concern in this regard goes beyond the present filing which projects NSPI’s 2002 test year expenses. It appears from the evidence 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 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.

[364] The Board has determined that NSPI shall undertake a 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.

[365] The Board also directs NSPI to provide, on an annual basis, a detailed analysis showing executive management expenses, including compensation, expenses, memberships and other personal benefits including loans. Only then can the Board be satisfied that expenses are

“reasonable and prudent and properly chargeable...” in accordance with Section 45(2) of the Act.

11.11 Sponsorships and Donations

[366] NSPI’s test year expenses relating to sponsorships and donations are disallowed. The Board reaffirms its 1996 ruling in this regard. The impact on the revenue

Document : 78377 142 requirement is a reduction of $635,800, which is the total proposed amount of $717,000 less the amount billed to affiliate entities.

11.12 Affiliate Activity

(A) Code of Conduct

[367] The Board is cognizant of the potential risk to ratepayers of unregulated affiliate activities. The Interim Code of Conduct was developed in order to institute a number of formalized measures to protect NSPI ratepayers. The Board finds that it is not appropriate, at this time, to give final approval to the Interim Code of Conduct. There appears to be considerable merit to the suggestion that Article 1.1 of the Code be amended to require that affiliate transactions must demonstrate a benefit to NSPI customers as opposed to causing them no harm. The Board intends to retain independent consultants to review the implications of such a change, and also to review the desirability of making further changes in light of the recommendations contained in the PWC report, the evidence presented at the hearing, and the findings of the Board in this decision.

[368] The Board directs that NSPI’s external auditors shall provide to the Board a schedule of their unadjusted differences (i.e., a summary of immaterial errors or exceptions), along with the annual audit report on compliance with the Code. In addition, the Board directs that copies of management or post-audit letters issued by NSPI’s external auditors in connection with their audit of NSPI’s compliance with the provisions of the Interim Code of Conduct be filed with the Board by the external auditors. Disclosure of this information supports the fundamental principles of fairness and accountability with respect to affiliate activities. At the present time, Emera appears to be in the

Document : 78377 143 process of transferring to various affiliates a number of activities previously carried out by NSPI.

The Board has concerns about the fairness of these transactions and, accordingly, the Board believes this reporting tool is a helpful instrument in protecting the interests of NSPI ratepayers.

(B) Agency Agreement

[369] During the course of the hearing, NSPI indicated that it intended to enter into an Agency Agreement with its affiliate, Emera Energy, covering fuel procurement, export electricity sales and gas sales. The transfer of these functions apparently took place in late 2001. In its evidence, NSPI has identified $672,000 as the amount of fees to be paid by NSPI to Emera Energy for the provision of fuel procurement services by Emera Energy during the test year.

[370] The Board is concerned that a major portion of NSPI’s fuel procurement activity, which the Board views as a core function of the Utility, representing a huge portion of

NSPI’s total costs, has been effectively transferred to an unregulated affiliate with no notice, regulatory approval or formal documentation by way of contract.

[371] The Board finds that the manner in which NSPI has conducted itself with respect to the Agency Agreement is not in keeping with the spirit and intent of the public utility regulatory regime in this Province. The Board is of the view that Emera wishes to transfer to affiliates many functions and activities which are carried out by NSPI. The Board is concerned that these activities could lead to a reduction in income to NSPI, thereby resulting in an increased burden on the ratepayers of NSPI. The Board’s concerns are exacerbated due to the inability of the NSPI witnesses to answer questions concerning the details surrounding the operations of Emera and its

Document : 78377 144 affiliate companies.

[372] Since no document was available to the Board during the proceeding, the intended terms of the agreement were unknown. The Board is not satisfied that, given the present structure of NSPI and Emera, ratepayers will be adequately protected from Emera’s apparent intention of levering off NSPI for the benefit of Emera shareholders.

[373] The Board disallows all fees paid by NSPI to Emera Energy in the test year for fuel procurement services, export electricity sales and gas sales as being imprudent. Moreover, the

Board directs that NSPI resume full responsibility for its own fuel procurement, export electricity sales and gas sales which the Board considers to be core functions of NSPI and an undertaking of the

Utility pursuant to Section 62 of the Act. There may be some point in the future when it would be prudent for these functions to be out-sourced, but this is neither an appropriate time, nor are these appropriate circumstances to consider doing so. No information or evaluation of Emera’s ability, performance and track record relative to other service providers is available to the Board and there are valid concerns relating to risk, conflict and harm to ratepayers should these functions be performed by an affiliate.

[374] On October 8, 2002, NSPI filed, on a confidential basis, a copy of an executed

“Agency and Surplus Energy Purchase and Sale Agreement” between Emera Energy and NSPI.

NSPI has not requested approval of the Agreement and takes the position that none is required. The

Board disagrees with this view. Further, the Board is not satisfied on the evidence that any fees or commissions paid by NSPI to Emergy Energy pursuant to the Agency Agreement are reasonable or prudent in the circumstances and, accordingly, such fees will not be chargeable against ratepayers.

Document : 78377 145

[375] Based on the information available to the Board this will result in a reduction of at least $672,000 in the revenue requirement. The Board directs NSPI to provide as part of its

Compliance Filing all fees paid in the test year to Emera Energy with respect to fuel procurement services, export electricity sales and gas sales in order for the Board to determine the precise amount to be disallowed as a result of this ruling.

[376] The Board also directs NSPI to engage the services of experts in the area of fuel procurement, especially coal, to develop in-house fuel procurement expertise as well as formalized policies and procedures governing fuel purchases. The Board is concerned that neither

NSPI nor Emera Energy appear to have proper procedures or practices in place to control and govern annual coal purchases of approximately $200 million. NSPI is further directed to report to the Board on the status of its in-house fuel procurement division and policy and procedure development within six months of the date of this decision, and to provide a follow-up report six months later.

[377] The Board further directs that prior to the future transfer of functions which, in the opinion of the Board, could constitute an undertaking of the utility, NSPI must receive the approval of the Board.

(C) Shared Services Allocation

[378] NSPI has identified that it uses the "four-factor" formula in determining what portion of the cost of services shared with its affiliates should be borne by NSPI. According to

NSPI’s auditors, the four-factor allocation method uses an average of the pro-rata percentage of

Emera’s consolidated assets; revenues; operating, maintenance and general expenses; and earnings

Document : 78377 146 before interest and taxes.

[379] The Board finds that the current method may result in unfairness. The ratepayers currently bear the risk of the potential for unfairness as some senior management members are engaged in fostering new businesses on behalf of Emera while NSPI ratepayers bear the lion’s share of corporate costs.

[380] The Board is of the opinion that, with respect to senior management, well- documented time allocation is the most appropriate method to determine how costs should be shared.

This is the best way to demonstrate that ratepayers are only charged for effort expended on their behalf in respect of NSPI functions.

[381] Accordingly, the Board directs NSPI to proceed to implement a cost allocation method, to be in place for the year 2003, based on well-documented time keeping records for those senior management employees having responsibilities for NSPI and any of its affiliates.

[382] For those costs not allocated on a "time allocation" basis, the Board directs that NSPI review and implement alternative methods of allocating its corporate support service costs.

The specific methods chosen should be based on measures that are specific to the particular units, such as space, number of employees, etc. Prior to the implementation of the specific allocation methods NSPI should prepare a report and submit it to the Board for approval. This report should also include a list of those senior management employees who will be accounting for their daily time and activities.

(D) Coal Transportation Contract

[383] The surface assets of CBDC, which were used to transport coal for NSPI, have

Document : 78377 147 been acquired by an NSPI affiliate and NSPI has included this component of its coal transportation costs in its revenue requirement, using CBDC’s contract price as a proxy for test year purposes. The

Board does not believe it is reasonable to use the CBDC price as representative of test year costs. In the Board’s view, it is reasonable to expect that NSPI, or its affiliate, will operate the surface assets at a lower cost than CBDC.

[384] Having reviewed the evidence and bearing in mind the comments of PWC with respect to the appropriate fair market value of CBDC’s transportation charges, the Board will reduce NSPI’s deemed expense for the use of the CBDC surface assets by $2 million. NSPI’s revenue requirement is reduced accordingly. Given its concerns arising from Ms. Hennings’ evidence, the Board is of the view that this is a conservative adjustment. The Board wishes to be satisfied that NSPI will be paying fair market value for the use of these facilities in the future. NSPI shall file information supporting its transportation expenses relating to these facilities within six months of the date of this decision. If the Board is not satisfied with this information, it reserves the right to engage suitable consultants to advise it concerning the fair market value of NSPI’s expenditures with respect to these facilities.

(E) Independence and Insulation

[385] The Board became increasingly concerned during the hearing with respect to the apparent lack of separation between NSPI and Emera and how this could negatively impact ratepayers. It is imperative, in the Board’s view, that NSPI and Emera avoid becoming so integrated that senior management is conflicted between the interests of Emera shareholders and the interests of

Document : 78377 148

NSPI ratepayers. It is clear to the Board that these interests can diverge from time to time.

[386] The Board does not wish to limit Emera’s legitimate business development initiatives, nor does it wish to prevent NSPI from achieving worthwhile efficiencies. Neither does it wish to impose impractical restrictions on the relationship between NSPI and Emera. However, the

Board must be satisfied that the utility’s assets are not transferred to affiliates without appropriate approval, regulatory oversight and objective arm’s length valuation. While the Board does not consider it is necessary for NSPI to have a separate Board of Directors at this time, it does believe certain changes in corporate governance would enhance the degree of insulation between NSPI and

Emera. Accordingly, the Board directs that effective for the year 2003:

1. Emera and NSPI use different auditing firms; and

2. NSPI’s audit committee shall have a different Chair than Emera’s audit

committee.

[387] The Board will continue to monitor this situation to determine what, if any, further changes should be made in the future.

11.13 Cost of Service, Rate Design and Other Rate-Making Issues

(A) Compliance Filing

[388] The revenue requirement approved by the Board is substantially lower than the revenue requirement requested by NSPI and, consequently, the resulting rates will also be lower than those proposed by NSPI. NSPI is directed to submit a Compliance Filing which will incorporate the adjustments and directives set out in this decision. The issues giving rise to the Board’s adjustments

Document : 78377 149 and directives have already been the subject of a lengthy public proceeding as have the Company’s proposed changes in rate structure. Intervenors have had a full and fair opportunity to challenge

NSPI’s application and present their respective positions through evidence and argument.

Accordingly, the Compliance Filing will be reviewed by the Board alone prior to the issuance of a final Order in this matter.

(B) Cost of Service Methodology

[389] The Board reaffirms the findings in its Cost of Service Decision dated

September 22, 1995. NSPI’s use of the Board’s approved methodology is accepted. Accordingly, for the purposes of setting rates, the Board will rely upon a COSS which begins with the study originally filed by NSPI, and reflects only the changes required to make the resulting study consistent with the findings made elsewhere in this decision.

[390] As part of the Compliance Filing, NSPI is directed to provide a COSS in the same format and detail as that provided in Appendix 2 of NSPI’s original filing. With that study,

NSPI is required to submit a brief statement identifying each change made from the original study, and explain how each change was required by, and conforms to, the Board’s decision in this proceeding.

(C) Revenue/Cost Ratios and Rate Shock

[391] While the Board affirms the commitment in its decision in NSPI’s last rate case to limit the class revenue requirements so that no class has an R/C ratio below 95% or above

105%, it also believes that, depending on the scale of a proposed rate increase, there may be

Document : 78377 150 justification for the Board to exercise some flexibility in the application of this general rule.

Judgement must be exercised in balancing the R/C ratio objective with the desire to avoid rate shock.

The Board finds that, to be reasonably applicable in a range of circumstances, the notion of rate shock must take into account the underlying average level of increase. Generally speaking, in considering the issue of rate shock, the Board will continue to strive towards its stated objective of keeping R/C ratios in the 95% to 105%, subject to the foregoing caveat. The Board will apply these principles in its review of NSPI’s Compliance Filing.

(D) Annually Adjusted Rates

[392] With respect to Annually Adjusted Rates, the Board directs that AARs for

2002 be developed using the formulas approved in the past. Development of the AARs for 2002 should begin with the data used in preparing the AARs included in NSPI’s initial evidence.

However, that data should be modified to take into account all of the changes required elsewhere in this decision. Similar changes, as required, should be made to the Mersey rate.

[393] As with the COSS, NSPI shall submit compliance versions of the AARs and the Mersey rate for Board review. The Compliance Filing shall include a statement, identifying each data change made for each rate, as well as a brief explanation of how each change conforms with the filings and directives made in this decision. The AARs will be implemented after the Compliance

Filing has been reviewed by the Board, the changes, if any, required by the Board have been made and the Board has issued a final Order approving the new rates. Once approved, however, the new rates will be effective as at January 1, 2002.

Document : 78377 151

(E) Rate Design

[394] The Board has determined that it will not address rate design issues at this time. Instead, it will simply require a rate design which furthers the Board’s goal of having R/C ratios in the 95% to 105% range, and which will minimize rate shock to the extent possible. The

Board finds that, for purposes of setting rates in this proceeding, the general rate design approach described on pages 53 and 54 of NSPI’s evidence should be followed. NSPI is directed to set class revenue requirements on the basis set out in Section 7.5 of this decision.

[395] The Board directs NSPI to develop and submit, as part of its Compliance

Filing, rates which meet all of the requirements prescribed by the Board to the fullest extent possible.

(F) Future Rate Design Proceeding

[396] The Board has decided to conduct a separate rate design proceeding to be held in 2003. Within the framework established by the ground rules set out in this decision, the parties will have the opportunity to propose changes in rate design. In order to minimize effort, parties will be allowed to enter testimony, exhibits and responses to information requests from the present proceeding into evidence in the rate design proceeding.

11.14 Municipal/Large Industrial Rate Relationship

[397] For the first time in more than 25 years NSPI has proposed in this application to "decouple" the Municipal rate from the Large Industrial rate. The Board is not persuaded that the arguments in favour of decoupling the rate are so compelling that any change in the longstanding

Document : 78377 152 practice needs to be made in advance of the rate design proceeding to be held pursuant to this decision. Accordingly, the Board directs that NSPI, in revising its rates in accordance with the directions set out above, shall maintain the Municipal and Large Industrial rate components at the same levels.

11.15 Green Rider Rate

[398] NSPI requested interim Board approval for a new rate which involves the establishment of a voluntary rate under which customers could pay a premium for electric service, in

$5 increments, to promote the use of electricity generated from environmentally-friendly renewable sources such as wind power. The Board has determined that while it will not give final approval for the green rider rate at this time, it will, however, approve the rate on an interim basis to be reviewed in detail during the next general rate proceeding.

11.16 Depreciation Expense

[399] NSPI forecasts depreciation expense of $102.8 million for the test year. The last depreciation study filed by NSPI was based on 1994 data. The Board considers that NSPI’s depreciation rates should be reviewed more frequently than once every seven years. NSPI is directed to retain an external depreciation consultant and to file a report with the Board for review not later than six months from the date of this decision.

11.17 Load Forecasting

Document : 78377 153

[400] The Board notes that Board staff and intervenors issued a number of IRs to

NSPI requesting evidence to support NSPI’s load forecast. While the Board finds that NSPI’s load forecast has been developed in a reasonable manner, it directs NSPI to file, as part of any future rate application, all supporting evidence pertaining to the development of its energy and peak demand forecasts.

11.18 Dalhousie Legal Aid Service

[401] DLAS’ principal recommendation to the Board is that it introduce a “rate subsidy program” under which low income residential customers would be subsidized by other customers of the utility. DLAS does not explain how such a program should be implemented.

[402] The Board has in the past rejected the principle of rate subsidies based on income disparity. The Board has given renewed consideration to the issue of rate subsidization based on income in light of the arguments put forward by Dalhousie Legal Aid Service. However, the Board continues to hold the view that the explanation of such rate subsidy programs is neither contemplated by S. 67(1) nor appropriate in the context of the regulation of public utilities.

Section 67(1) of the Act is pertinent to any discussion of rate subsidies:

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.

11.19 Regulatory Process

[403] The Board is aware of NSPI’s complaint with respect to the length of time

Document : 78377 154 involved in completing this proceeding. The Board is of the view that, relative to other North

American regulatory jurisdictions, the length of this proceeding was not unreasonable given the complexity of the material; the lengthy interval between rate cases; the scope of the issues; the magnitude and potential impact of the proposed increases; and the difficulties between the parties relating to the availability of information.

[404] The Board does not agree with NSPI’s position that it was subjected to an

"...extraordinary ‘discovery’ process authorized by the Board in this case." NSPI is a monopoly utility with a revenue requirement that is subject to public scrutiny. It is NSPI, not the intervenors, which has the burden of proof in establishing that a rate increase is warranted.

[405] The Board will facilitate a technical conference, in advance of the next hearing, between NSPI and intervenors for the purpose of streamlining the information request and response process. The Board hopes that this will result in a shorter hearing and less acrimony between the parties. This conference will occur following the filing of NSPI’s application and prior to the issue of IRs.

[406] The Board does not object in principle to a settlement process in advance of the hearing provided that all classes of ratepayers are represented in these discussions. To this end, should NSPI wish to pursue a settlement process with intervenors, the Board will appoint a consultant, at NSPI’s expense, to act as a consumer advocate for otherwise under-represented groups of customers (i.e., domestic, small commercial). The Board may also determine that it would be in the public interest to ensure that these customers are represented by a consumer advocate at the technical conference referred to above. It goes without saying, of course, that any settlement

Document : 78377 155 agreement reached by the parties would be subject to scrutiny at a public hearing by the Board.

An Order will issue accordingly.

DATED at Halifax, Nova Scotia, this 23rd day of October, 2002.

______John A. Morash, Chair

______Margaret A.M. Shears, Vice-chair

______John L. Harris, Member APPENDIX - A List of Witnesses

On behalf of: Witness

NSPI Christopher Huskilson James Taylor Melvin Whalen Michael O’Neil Zeda Redden Mary Lambert J. A. Watkins Richard D. Falconer Kathleen C. McShane

ANNAPOLIS GROUP Emily S. Medine

NSUARB James A. Rothschild Dr. John Stutz

ECANS James R. Carpenter Norman Pearce Richard Gerrior Marc D. LeClerc William St. Leger

PROVINCE OF NOVA SCOTIA Dr. Lawrence Kryzanowski Dr. Gordon S. Roberts

Document : 78377 156

STORA ENSO Sharon Hennings & BOWATER MERSEY Dr. Alan Rosenberg Fred Hussey

EVENING SESSION Dick Smyth, Vice-pres. - Canadian Manufacturers & Exporters

Eric Twohig - Renewable Energy Services Limited

Richard Freeman & Doug Ledwidge-Forest Products Assoc. of NS

Patricia Pilkington - residential customers

Mayor C. Cotter and Deputy Mayor Jim Fraser - Town of Trenton

Joey O’Brien - Ski Martock

Councillor Peter Newton - Municipality of Annapolis Co.

Paul O’Hara - Northend Community Health Centre

Bill Cruickshank, Recreation Facility Assoc. of NS

Alasdair Sinclair and Hilary Fraser - Face of Poverty Consultation

Warden Richard Cotton - Municipality of the County of Richmond

Mayor Billy Joe MacLean - Town of Port Hawkesbury

Warden Herbert DeLorey - Municipality of the Co. of Antigonish

Warden A. J. McDougall - Municipality of the Co. of Inverness

Perry Chandler - Strait Area Chamber of Commerce

Duncan Cross, Atlantic Region - Canadian Plastics Industry Assoc.

Manning MacDonald, MLA Cape Breton South

Michel Samson, MLA Richmond

Jerry Ackerman

OTHERS W. A. (Bill) Macneil, P.Eng. on behalf O&Y Enterprise - Purdy’s Wharf

Jo Sheppard, Lunenburg Co., NS

Document : 78377 157

APPENDIX - B List of Formal Intervenors

Annapolis Group Inc. Robert G. Grant, Q.C. and Atlantic Shopping Centres Ltd. Nancy G. Rubin Avon Valley Greenhouses Ltd. Ben’s Limited Canadian Salt Company Limited Capital District Health Authority Cerescorp Company CKF Inc. Council of Nova Scotia University Presidents Crown Fibre Tube Inc. EastLink Limited (Bragg Communications Inc.) (Bay Communications Inc.) (Halifax Cablevision Limited) (K-Right Communications Limited) (Access Communications Inc.) (Access Bedford Sackville Cablevision Limited) (Kings Cable Limited) Envirosystems Inc. Halifax Grain Elevator Limited Halifax International Airport Authority Halterm Limited High Liner Foods Inc. Irving Oil Limited Irving Shipbuilding Inc. Izaak Walton Killam Health Centre J. D. Irving Ltd., Sawmill Division Mactara Limited Maritime Paper Products Ltd. Michelin North America (Canada) Inc. Minas Basin Pulp & Paper Company Ltd. Mount Saint Vincent University Nova Scotia School Boards Association Oxford Frozen Foods Limited PolyCello Sable Offshore Energy Inc. Scotia Investments Ltd. Sifto Canada Inc Sobeys Group Inc. Sobey Leased Properties Ltd. Statia Terminals Canada Incorporated

Antigonish, Town of Brian R. MacNeil Bowater Mersey Paper Company Limited George Cooper, Q.C. and Stora Enso Port Hawkesbury Limited David MacDougall Canadian Oil Heat Association - Nova Scotia Chapter Debbie Jamieson, VP Canadian Plastics Industry Association Duncan Cross, Exec. Director Canso, Town of T. Troy Jenkins, CAO Cape Breton Regional Municipality John Whalley Dalhousie Legal Aid Service Claire McNeil, Staff Lawyer Dalhousie University Peter Howitt, MBA, P. Eng. Donkin Resources Limited Stephen Farrell, P. Eng., Pres. Electricity Consumers Alliance of Nova Scotia (ECANS) John Woods, P. Eng., Exec. Dir. Forest Products Association of Nova Scotia Steve D. Talbot, Exec. Director GasWorks Installations Inc. John H. Reynolds, P. Eng and Dwight E. Jeans Halifax Port Authority Dennis W. Creamer Halifax Regional Municipality Mary Ellen Donovan, HRM Liberal Caucus Wayne Gaudet, Interim Leader Lighthouse Energy Inc. Ray Ritcey Lunenburg, Town of Bea Renton and Lunenburg Electric Utility Municipal Electric Utilities of Nova Scotia Co-operative Don Regan, Berwick Electric NB Power Rick Mitton NDP Caucus Shawn Fuller, Mgr., Research Nova Construction Company Limited Mark MacDonald, Q.C. Province of Nova Scotia Jeannine Lagasse Renewable Energy Services Limited D. R. Harper, Eric Twohig and

Document : 78377 158

Brian Wattling TrentonWorks Limited A. William Moreira, Q. C. and ACA Cooperative Ltd. & Eastern Protein Foods Ben Durnford Cherubini Metal Works Limited Maritime Steel and Foundries Limited United Steel Workers of America - Dist. 6 John Kingston Wentworth Valley Developments Ltd. Steven Wilson

Informal Intervenor

Kimberly-Clark Nova Scotia Jack Blakeney

Document : 78377 159

APPENDIX - C

INTERIM CODE OF CONDUCT

ORDER NSUARB - NSPI-P-167

IN THE MATTER OF THE PUBLIC UTILITIES ACT

-and-

IN THE MATTER OF AN INTERIM CODE OF CONDUCT to govern the relations between NOVA SCOTIA POWER INC. and its AFFILIATES

BEFORE: John A. Morash, C.A., Chair Margaret A.M. Shears, Vice-chair John L. Harris, Q.C., Member

ORDER

WHEREAS Nova Scotia Power Inc. (NSPI) is a body corporate incorporated pursuant to the Companies Act and is engaged in the production and supply of electrical energy in Nova Scotia;

AND WHEREAS NSPI is a public utility and its business activities are regulated by the Nova Scotia Utility and Review Board (Board) pursuant to the Public Utilities Act;

AND WHEREAS NSPI is the principal operating subsidiary of, and is wholly owned by, Emera Inc. (Emera), formerly known as NS Power Holdings Incorporated, a body corporate incorporated pursuant to the Companies Act on July 23, 1998;

AND WHEREAS Emera, by itself and through subsidiaries other than NSPI, has a number of business interests and engages in a number of business activities which are not subject to regulation under the Public Utilities Act;

AND WHEREAS the Board stated the following in its decision dated March 4, 1996, on an application by NSPI for a general rate increase: “The Board will review the issues involved in ensuring that unregulated subsidiaries are not cross-subsidized by the customers of the utility and may at a later date prescribe additional cost separation procedures to be followed by NSPI”;

Document : DECISION N.S. BOARD - 5 FÉV. 03.DOC 160

AND WHEREAS NSPI recognizes that the ratepayers of NSPI should not be harmed by transactions between NSPI and its affiliates;

AND WHEREAS the Board has engaged Consultants to assist it in developing a Code of Conduct which would apply to the business activities of NSPI and its affiliates;

AND WHEREAS the Consultants have engaged in extensive discussions with NSPI with regard to the form and content of a Code of Conduct;

AND WHEREAS the Board has reviewed the Code of Conduct developed by its Consultants and NSPI, and is prepared to approve it on an interim basis;

AND WHEREAS the Code of Conduct is a public document which shall be subject to review at a future general rate hearing or, in the discretion of the Board, at an earlier public hearing;

IT IS ORDERED AND DECLARED THAT:

1. The NSPI Interim Code of Conduct attached hereto as Schedule “A” is hereby approved;

2. The Interim Code of Conduct shall come into force on September 16, 2001;

3. The Interim Code of Conduct shall remain in force until a final Code of Conduct is approved by the Board pursuant to a future general rate hearing or pursuant to an earlier public hearing at the discretion of the Board;

4. Notwithstanding that the Interim Code of Conduct does not formally come into force until September 16, 2001, NSPI and its affiliates shall, to the extent feasible, conduct their business activities in accordance with the provisions of the Interim Code of Conduct, effective immediately.

DATED at Halifax, Nova Scotia, this 16th day of March, 2001.

______Clerk of the Board

Document : DECISION N.S. BOARD - 5 FÉV. 03.DOC 161

Schedule “A” to Board Order dated March 16, 2001

NOVA SCOTIA POWER INC. INTERIM CODE OF CONDUCT Effective September 16, 2001

1.0 PURPOSE

1.1 The primary purpose of this Code of Conduct is to ensure that the customers of Nova Scotia Power Inc. (NSPI) are not harmed by transactions between NSPI and its affiliates1.

2.0 STATEMENT OF PRINCIPLES

2.1 NSPI will neither subsidize, nor be subsidized by an affiliate’s current or prospective activities. This means that, among other things, NSPI’s customers will not bear the risks nor share the rewards of an affiliate’s activities.

2.2 Competition in markets where NSPI’s affiliates are active will not be impaired by non-market behaviour by NSPI.

3.0 CORPORATE STRUCTURE

Objectives

To separate regulated electric and other utility services2 from affiliate activities.

1 For the purposes of this Code of Conduct, the term “affiliate” shall be interpreted in accordance with Sections 2(2), 2(3), and 2(4) of the Nova Scotia Companies Act.

2 Regulated electric and other utility services are those covered by the Public Utilities Act.

Document : DECISION N.S. BOARD - 5 FÉV. 03.DOC 162

Protocols

3.1 EMERA, the parent company of NSPI, will create and maintain a corporate organizational structure which ensures that regulated electric and other utility services are provided solely by NSPI and by no other affiliate.

3.2 NSPI will maintain a complete list of all of its affiliates. The list will include the name and address of each affiliate, a brief description of its activities and the names, addresses and telephone numbers of all of its officers. The list will be kept on open file with the Nova Scotia Utility and Review Board (Board).

4.0 UTILITY MANAGEMENT

Objectives

To dedicate to the provision of regulated services, in terms of quality and numbers, a management team capable of maintaining a superior level of performance, at the same time as NSPI affiliates are expanding into other business activities.

Protocols

4.1 NSPI will maintain a management team capable of delivering a superior level of performance.

4.2 NSPI will prepare and submit to the Board an annual report which summarizes utility results. The report format, and contents thereof, shall be agreed upon in advance between NSPI and the Board.

5.0 UTILITY FINANCING

Objectives To maintain a capital structure for NSPI which is in accordance with applicable Board decisions.

Protocols

5.1 NSPI’s capital structure will reflect the Board approved capital structure.

5.2 NSPI’s capital structure will not be used to subsidize

Document : DECISION N.S. BOARD - 5 FÉV. 03.DOC 163

affiliate activities. Affiliate risks or losses will not be borne by NSPI’s customers.

5.3 NSPI shall not, without the prior approval of the Board, provide loans to, guarantee the indebtedness of, or invest in securities of an affiliate.

6.0 FAIR DEALING

Objectives

To avoid discrimination in the matter of pricing or in any other manner against non-affiliated buyers of regulated electric utility services.

To avoid NSPI subsidizing or being subsidized by the activities of affiliates.

Protocols

6.1 NSPI will provide access to regulated utility services on a non-discriminatory basis.

6.2 The financial records of NSPI, as well as NSPI’s information systems, will be kept separate from those of its affiliates.

6.3 NSPI will not directly or indirectly state, imply or offer any preference or favoured treatment to NSPI’s affiliates or persons using affiliate services.

6.4 NSPI will not provide confidential customer information to affiliates or other persons without prior customer consent.

6.5 NSPI will provide customer information to NSPI affiliates and non-affiliates in a non-discriminatory manner.

6.6 NSPI will charge Board approved rates for all regulated electric and other utility services provided to affiliates.

6.7 NSPI will charge and be charged a market rate of return for any assistance it provides to or receives from affiliates by way of a guarantee or loan.

6.8 NSPI will charge and be charged prices which reflect fair market value for all non-regulated utility goods and services provided to affiliates or purchased from

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affiliates, provided that in no case shall NSPI supply such goods and services at a loss. 6.9 Where prices based on market value cannot be established, NSPI will charge prices which reflect the utility’s fully- allocated costs for the goods and services provided.

6.10 Where a capital asset is transferred from NSPI to an affiliate or from an affiliate to NSPI, that asset will be transferred at a price to be approved by the Board in advance.

6.11 The costs of corporate support services3 will be fairly allocated between NSPI and its affiliates. The allocation factor employed will depend on the nature of the corporate support services.

7.0 ACCOUNTING COMPLIANCE

Objectives

To separately and fully account for the value of goods, services, financial and other support delivered to or from NSPI and its affiliates.

Protocols

7.1 NSPI shall report annually to the Board the following information:

(a) A detailed listing of all assets, services and products provided to and from NSPI and each of its affiliated companies. (b) Each item on the listing should indicate the price

3 Corporate support services are those Management and Administrative services which are provided to affiliates by NSPI. Examples include Board of Directors’ costs, Public and Regulatory Affairs, Finance and Administration, Corporate Services, Legal, Human Resources and Information Technology.

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received or paid and, as appropriate, the relevant fully allocated costs or market values. (c) Where fair market value is used, an explanation should be provided as to how the value was determined, including the comparative source for the value. (d) Where cost allocations are involved, a description of the cost allocators and methods used to make the allocations should be included. (e) A summary of corporate services and the methodology for ensuring fair allocations of these costs.

7.2 NSPI shall submit an annual report to the Board by its external auditors, in a form satisfactory to the Board, which indicates whether the company is in compliance with the provisions of this Code of Conduct.

7.3 In order to monitor compliance, the Board at any time may review the records of NSPI and, so far as is required for this sole purpose, the records of NSPI affiliates.

8.0 EMPLOYEE COMPLIANCE

Objectives

To ensure understanding of and compliance with this Code of Conduct.

Protocols

8.1 NSPI will inform all its managers and employees directly involved in affiliate activities of their expected behaviour relative to the Code of Conduct and will undertake annual management reviews to ensure compliance.

9.0 GENERAL

9.1 All reports referred to in this document shall be provided by April 30 in respect of each preceding year.

9.2 This Code of Conduct shall become effective six (6) months following approval by the Board.

APPENDIX - D BOARD ORDER ON DISCLOSURE

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ORDER NSPI-P-875 (Preliminary Motion)

NOVA SCOTIA UTILITY AND REVIEW BOARD

IN THE MATTER OF THE PUBLIC UTILITIES ACT

- and -

IN THE MATTER OF an Application by Stora Enso Port Hawkesbury Limited, Bowater Mersey Paper Company Limited and Annapolis Group et al to compel Nova Scotia Power Incorporated to Provide Better and Fuller Responses to certain Information Requests filed by the Applicants as a result of a request by Nova Scotia Power Incorporated for approval of Changes to its Rates, Charges and Regulations

BEFORE: John A. Morash, C.A., Chair Margaret A. M. Shears, Vice-chair John L. Harris, Q.C., Member

O R D E R

WHEREAS the Applicants, Stora Enso Port Hawkesbury Limited, Bowater Mersey

Paper Company Limited (SEB) and the Annapolis Group et al (Annapolis) are formal Intervenors in

the application by Nova Scotia Power Incorporated (NSPI) for changes to its Rates, Charges and

Regulations, and have requested information from NSPI in accordance with the Hearing Order

issued by the Board;

AND WHEREAS in submissions dated March 8, 2002, SEB and Annapolis

requested that the Board compel NSPI to provide better and fuller responses to certain information

requests which the Applicants state are required in order to facilitate a satisfactory level of review of

fuel costs by experts retained by the Applicants in preparation for the upcoming rate hearing; and

which have been categorized by SEB as tender information; contracts (fuel and transportation); the

Cape Breton Development Corporation (CBDC) contract and information concerning the buyout;

Document : DECISION N.S. BOARD - 5 FÉV. 03.DOC 167 unit figures for individual plants including heat rates, generation, etc.; and the assumptions and calculations used by NSPI to produce the summary information which has been provided;

AND WHEREAS after having invited submissions on the matter from all

Intervenors, the Board held a hearing on the application on March 11, 2002 at which time NSPI argued that it should not be compelled to disclose the information sought as it is confidential and, if disclosed, could result in commercial harm to NSPI, and that NSPI was not satisfied that such harm could be mitigated by limiting access to such information to certain parties on a confidential basis;

AND WHEREAS the following persons participated in the said hearing:

George T. H. Cooper, Q.C., David S. MacDougall and Sharon Hennings for SEB Nancy G. Rubin and Emily Medine for Annapolis Benjamin R. Durnford for Trentonworks et al Jeannine A. Lagassé for the Province of Nova Scotia Karen L. Brown for Halifax Regional Municipality John P. Woods for Electricity Consumers Alliance of Nova Scotia Daniel M. Campbell, Q.C., for NSPI S. Bruce Outhouse, Q.C., Board Counsel AND WHEREAS pursuant to Board Regulatory Rule 7(9) the Board has the discretion to determine whether and on what terms information, in respect of which a claim of confidentiality has been made, should be disclosed;

AND WHEREAS in a decision of the Board dated June 19, 1990 in the matter of an application for information by Scotia Biomass Power Incorporated, the Board made the following statement explaining its decision to permit access to the information in question on a confidential basis:

It has been argued by the respondents that even though the information is relevant, Scotia Biomass has no real need for it because (1) the Board’s staff and consultants have the information and Scotia Biomass and the other intervenors can rely on the Board to correctly analyze and evaluate this information... The Board does not agree with these arguments. The Board’s experts are, in its opinion, very competent in their field. However, they are not infallible. The Board will benefit from having not only the

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Corporation’s testimony but also the testimony of its own experts tested by well prepared intervenors... In a matter of such evident importance to the intervenors it is essential that they not only be able to test the evidence of other witnesses but they have access to all information which may be necessary to build their own case. [Board Decision, June 19, 1990, pp. 6 & 7]

AND WHEREAS after carefully reviewing the submissions of the participants, the

Board has determined that the findings of the Board as quoted above are applicable to the present

circumstances and that the public interest is best served in these circumstances by directing the

release of the information, as described in summary form above, on a limited and confidential basis

in accordance with the process set out in this Order;

AND WHEREAS the Board further notes that it retains the right to assess costs and/or pursue appropriate action against any individual who violates the undertaking to maintain the confidentiality of this information;

IT IS HEREBY ORDERED THAT:

1. NSPI shall provide Designated Confidential Information, as defined herein, to the Designated Recipients set out below.

2. Designated Confidential Information shall consist of the following: (a) fuel supply contracts; (b) fuel transportation contracts; (c) tender documentation related to (a) and (b) above; (d) correspondence and documents relating to negotiation of termination of the long-term CBDC coal supply contract, (sometimes referred to as the contract “buyout”) including original coal contract and amendments, termination agreement and arbitration agreement; (e) generating unit-specific production and cost information, on a monthly basis, including but not limited to heat rates, monthly forecast MWh of supply, cost of each fuel source, and quantities and qualities of fuel to be used by fuel source; (f) an explanation of the assumptions and calculations underlying the information

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provided above.

3. Access to Designated Confidential Information shall be restricted to the following Designated Recipients: David S. MacDougall and Sharon Hennings; Robert G. Grant, Q.C., Nancy G. Rubin and Emily Medine A. William Moreira, Q.C. and Benjamin R. Durnford Jeannine A. Lagassé Mary Ellen Donovan and Karen L. Brown Donald Regan and John P. Woods

4. As a condition precedent to receiving Designated Confidential Information, the Designated Recipients shall sign the form of undertaking attached as Schedule “A” to this Order.

5. No Designated Confidential Information furnished by NSPI shall be given or communicated to persons other than the Designated Recipients authorized under this Order. For greater certainty, no Designated Confidential Information shall be provided to the clients of Designated Recipients, to Intervenors or to employees, officers or members of Intervenors.

6. NSPI shall make the Designated Confidential Information (including copies if necessary) available to the Designated Recipients for review at its head office. No documentation provided under this Order shall be removed from NSPI’s premises without the consent of NSPI. Designated Recipients may take such notes as may be necessary solely for the purposes of this proceeding. Such notes shall be treated as Designated Confidential Information.

7. Where a reference to Designated Confidential Information is required in pre-filed testimony, briefs, other legal documents or arguments, such reference shall be by citation of title or exhibit number only or by some other non-confidential description which protects the confidentiality of the information. In such circumstances, counsel and those persons bound by this Order shall make every reasonable effort to preserve the confidentiality of the information provided by NSPI. The Board may draw upon all Designated Confidential Information in the record in the deliberation of any decision or order it may issue, but the Board will avoid the reproduction in its decision of any Designated Confidential Information.

8. Where an Intervenor files testimony which contains Designated Confidential Information, the testimony must be filed on a confidential basis and the Designated Confidential Information

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must be specifically identified as such. In addition, the Board will sit in camera to hear such evidence if requested by NSPI.

9. Should any appeal or challenge to the Board’s decision in this proceeding be taken, any portions of the record which have been designated confidential in accordance with this Order shall be forwarded to the court in accordance with applicable laws and procedures but under seal and designated confidential.

10. Within 30 days after the Board has reached a final decision in this proceeding, each person to whom Designated Confidential Information has been provided shall return to NSPI such Designated Confidential Information and shall destroy all documents, notes and other materials containing or reflecting, directly or indirectly, Designated Confidential Information, and shall provide an affidavit of compliance to NSPI respecting same.

11. The date for filing intervenor evidence is extended until the later of March 25, 2002 and twelve (12) calendar days from the receipt of the information provided by NSPI to the Designated Recipients pursuant to this Order.

DATED at Halifax, Nova Scotia, this 12th day of March, 2002.

______Clerk of the Board

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SCHEDULE “A”

NOVA SCOTIA UTILITY AND REVIEW BOARD

IN THE MATTER OF THE PUBLIC UTILITIES ACT

- and -

IN THE MATTER OF an Application by Stora Enso Port Hawkesbury Limited, Bowater Mersey Paper Company Limited and Annapolis Group et al to compel Nova Scotia Power Incorporated to Provide Better and Fuller Responses to certain Information Requests filed by the Applicants as a result of a request by Nova Scotia Power Incorporated for approval of Changes to its Rates, Charges and Regulations

UNDERTAKING

I, , of having read the Order of the Nova Scotia Utility and Review Board dated the 12th day of March, 2002 concerning the provision to me of designated confidential information, hereby undertake and agree to abide by all the terms thereof.

DATED at , this day of March, 2002.

______

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APPENDIX - E TEXT OF BOARD LETTER OF CLARIFICATION

March 22, 2002

By Fax: 420-1417

Ms. Nancy G. Rubin Stewart McKelvey Stirling Scales 900-1959 Upper Water St P. O. Box 997 Halifax, NS B3J 2X2

Dear Ms. Rubin :

Nova Scotia Power Inc. - Application for approval of certain revisions to its Rates, Charges and Regulations -Application by Stora Enso Port Hawkesbury Limited, Bowater Mersey Paper Company Limited and Annapolis Group et al to compel Nova Scotia Power Incorporated to Provide Better and Fuller Responses to certain Information Requests - Preliminary Hearing - P-875 This letter is further to your request, dated March 21, 2002, for clarification as to whether Section 2(d) of the Order of the Board dated March 12, 2002, which required Nova Scotia Power Incorporated (NSPI) to provide better and fuller responses to certain information requests on a limited and confidential basis, can be interpreted to include the memorandum from NSPI management to the Board of Directors concerning the costs incurred in the termination of the long term contract with Cape Breton Development Corporation (CBDC).

The Board has received a submission from Counsel for NSPI objecting to the disclosure of this document on the basis that documents provided to the Board of Directors of NSPI are particularly sensitive and are not included in the wording of the Board’s March 12, 2002 Order. Further, NSPI states that disclosure of the information to your firm, which evidently also represents CBDC, is “particularly inappropriate”.

The Board has reviewed the submissions in this matter and has determined that Section 2(d) of the Order dated March 12, 2002 can reasonably be interpreted to include the memorandum which is the subject of this dispute. Further, with respect to the issue of your firm acting for CBDC, in the Board’s view, the confidentiality order signed by yourself and Mr. Grant should adequately address this matter. The Board further understands that neither you nor Mr. Grant represent CBDC.

Yours truly,

Nancy McNeil Regulatory Affairs Officers/Clerk c.c. Mr. Bruce Outhouse, Q.C., Board Counsel Fax: 429-7347 Mr. Peter Gurnham, Q.C. Fax: 421-3130 Mr. David MacDougall Fax: 425-6350 Formal Intervenors

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